Q1 2020 Earnings Call
Greetings and welcome to the Qiwi P. resources first quarter 2020 conference call.
At this time all participants are in listen only mode. A question an absolutely an answer session will follow the formal presentation. If anyone should require operator assistance. During this teleconference. Please press star zero on your telephone keypad.
Please note this conference is being recorded.
I'll now turn the conference over to our host William Katz Director of Investor Relations. Thank you you may begin.
Thank you Diego and good morning, everyone. Thank you for joining us today, but you would be resources first quarter 2020 results conference call.
With me today, a little wider Tim Connor, President and Chief Executive Officer.
Bill BZ, Chief Financial Officer and Treasurer.
Joe Radigan Vice President of energy.
Did you know dates already please go to our website <unk> dot com to obtain copies of our earnings release masking tape tables with our financial results along with a slide presentation with supporting materials.
Today's conference call, we will use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA.
So that's the seat.
And free cash flow.
These measures are reconciled the most comparable GAAP measure in the earnings release or does he see filings.
In addition, we'll be making numerous forward looking statements remind everyone that our actual results could differ materially from our forward looking statements variety of reasons, many of which will be under control. Your for everyone normal robust Ford you speak the disclaimer discussion of these risk factors.
Basic our business in our earnings release that CPC filings with that I'll now turn the call over time.
Thank you will and good morning, everybody didn't lucky for joining the told today.
Beginning with an overview actions, we've taken to address the current environment.
Followed by update over first quarter operational performance since January of 19, we're focused on delivering value over volume and are holding firm to this principle started these unprecedented times. Following my update I'll turn color build to discuss our first quarter financial performance and to provide an update on our liquidity position.
In mid March when WG, <unk> $35 barrel, we announced plans to lay down one Reagan spend fracking operations in the Permian affected my first we also suspended re frac operations in the Williston basin. The following week prices continue to drop 'em, we immediately suspended pricing operations in the Permian and notified the tech.
Rig, but it wouldn't be released its action leaves us with one rig operating in the Permian to build the necessary duck towns to execute the 2021 program second rig located in the Wilson is drilling the discount.
Which is a lease holding operation that's drilling program will complete operations.
During July we plan to complete to the six wells being drilled to meet our lease obligations all other operators activities and the Wilson have been suspended.
Finally, we have developed a detailed well shouldn't strategy that is independent of our hedge position.
Lower Elouise <unk> increase even though.
In general we're prepared to shut in wells once the netback price in the field was equal to the burden L. are we plus the transportation expense, we've taken into account technical consideration. So avoid any significant impacts you ours and leasehold obligations to avoid losses acreage. We have started shutting in wells and given the actual spread a personal berman.
During the next few months, we're prepared to take more significant action if necessary. We have also delayed the start up of 10 completed wells in D.S. Yoo 11, 25, and county line until prices improves we ran numerous financial models to understand the impact of production curtailments on free cash flow given the reduction to very loyal what we.
Transportation expense and the improvements are hedged our hedge position as prices drops free cash flow is not significantly impacted what price drops and we shut in additional production.
We recently added hedges for May through July $30, a barrels per mcfe a period of time, but is expected to experts most significant impact to the mass. We now have 30 million barrels hedged to cover the remainder of the year at an average price of approximately $56.50.
Although current operational performance may not be front of mind supposed to best suburbs and Busters I do believe it is critically important to understand what we have been able to achieve during the first quarter to help project our ability to perform once markets begin to recover.
We're very pleased with the operational performance in the quarter and are on or ahead of of original guidance in all categories.
Drilling and completions operations were complete for the 25, well Oh 312 DS you in County line before spending fracking operations.
In the Permian, we're very pleased with all aspects of this development projects as you can see from slide six and seven of our IR deck Tecan cumulative production rates are exceeding expectations and in most benches significantly exceeding our its peer performance buzzard curve shown on slide six was based on GDP his previous experiences.
County line, along with evaluating all sit operated well performance. The tank is performing as expected with the deeper benches, producing oil quickly while the shallower zones take time to deepwater the tanker for producing all type curve rates.
Significant outperformance is primarily coming from the Wolfcamp deemed sprayberry C benches, the spraberry b benches, performing better than expected in the middle and lower Spraberry wells are now hitting or expected peak rates after helping to the water attacks. We have three wells with a 30 day average greater than 2000 barrels a day.
For additional wells with 30 day average greater than 1500 barrels a day and 10 additional wells exceeding a thousand barrels a day for 30 days. This positive performance is a strong affirmation of the modifications that were made to our limited entry practices I'll discuss some slight aided they are done.
Reduced cluster spacing, along with fewer and smaller perforations has resulted in a higher perforation friction and most importantly improve cluster efficiency.
Our drilling and completions team also continues to improve on both cost and efficiency as you can see from slide nine of the our dogs. Our most recent wells in D.S. Yoo O 312 delivered in a.
Drilled and completed cost of $500 foot and Fracked over 36 on the lateral feet per day, which remains peer leading.
In the Williston, we've sustained a sustained production from the first of two wells refracts in the quarter, while the second wells being drilled out to prepare for production. We're encouraged by the results as demonstrated on slide 10 of the IR debts.
We understand that these results might be overwhelmed by other concerns on the current market, but it is critically important for investors to understand QD feasibility to efficiently develop our high quality acreage position on the Midland Basin. Once the market comes back in balance.
Lowered the 2020 capital budget by 32% down to 385 doing it.
Lets keep in mind that our original plan was front end loaded and we've deployed $180 million capital in the first quarter, we have significantly lowered spend during the second third quarters and never change flexibility to lower the fourth quarter spend further price recovery does not support for during resuming drilling and fracking operations.
Uh huh.
This plan is expected to deliver more than $100 million free cash flow in 2020 at a range from a price and shut in scenarios. In summary, we have adjusted airplanes to allow us to navigate through appeared at low price, while continuing to generate significant free cash flow.
Our recent development activity in county line demonstrates our ability to be at low cost developer.
Core acreage, while delivering outstanding well results, we're well positioned to move through this unprecedented reductions man and we look forward to things gradually returning to normal I'll now turn the call over to build to discuss first quarter financial results along with information on our liquidity position.
Thank you Tim and good morning, everyone over the next few minutes I'll provide some details on our first quarter results and update our got 2020 guidance before opening the call up for queuing day.
For the first quarter 2020 reported net income of $367 million compared to a net loss of $110 million in the fourth quarter of 2019.
<unk> net income was a 407 million dollar unrealized gain associated with our commodity derivatives position.
At the end of the first quarter. The derivatives portfolio was a net asset of $390 million compared to a net liability of $18 million at the ended the fourth quarter.
And the first quarter, we generated $173.9 million of adjusted EBITDA, a modest decrease from the hundred 83.8 million generated in the fourth quarter of 2019, primarily driven by a decrease in equivalent production and realized prices in the first quarter compared with the fourth quarter combined to total although he and transportation expense was down.
Slightly to a combined to $54 million and DNA was down more than $15 million into first quarter compared with the fourth quarter.
We continue to enter into commodity derivative contracts during the quarter and we currently hold contracts excluding basis swaps totaling 13 million barrels of oil for the remaining nine months of 2020, the average fixed price of the remaining contract for the year is approximately $56 in 50 cents per barrel. Please see the 10-Q for additional details on a derivative port.
Polio.
During the first quarter, we generated net cash provided by operating activities of $151.9 million and as expected with our capital program being front end loaded reported a free cash flow outspend of $31.6 million, a 40 million dollar improvement compared with the outspend in the first quarter of 2019.
The improvement was primarily due to an increase in unrealized derivative gains and decreases in Louisiana expense, partially offset by a decrease in oil gas and NGL sales and an increase to accrued capital expenditures.
And the first quarter, we booked a 165.4 million dollar income tax receivable largely tied to the carriers Act was passed in March of 2020. If you recall, we received a 73.9 million dollar AMTI credit refund in 2019 and had originally forecasted an additional $75 million AMTI credit refunds.
Over the next three years, including 37 million in 2020.
The Cures act allowed us to accelerate all the remaining 75 million dollar of AMTI credit refunds into calendar year 2020.
In addition, the carries that permits us to carry back our 2018 net operating loss into 2014, when we pay tax in conjunction with our midstream business sale.
Creating an additional $91 million AMTI credit.
Also expect to receive this year in total we now expect receive approximately $165 million of tax refunds during the second half of 2020.
With regard to our balance sheet at the end of the first quarter total assets were approximately $5.9 billion and total shareholders equity was approximately $3 billion.
Total gross debt was approximately $1.9 billion, we had no borrowings outstanding under our revolving credit facility and we had $70 million of cash.
During the first quarter, we repurchased approximately 50 million in principle amount of our 2021 notes 35 million of R. 22 notes and 13 million of our 23 notes all that discounts, reducing our outstanding gross debt by approximately $100 million to a total of 1.9 billion outstanding.
Before moving onto guidance I wanted to spend a few moments discussing our capital structure and liquidity as shown on slide 11 through 13 in the IR deck.
Starting with our senior notes at March 31st we had 1.9 billion of notes outstanding with maturities ranging from March 1st 2021 to March 1st 2026, and coupons ranging from five in a quarter to 6.875%.
No its require interest he paid semiannually, our unsecured and right equally with all of our other existing unsecured obligations. We can redeem the notes at any time before their maturity at a redemption price based on a make whole them out plus accrued interest.
The indentures that govern the notes contain customary events of default and covenants that may limit our ability to among other things placed liens on our assets.
Our revolving credit facility, which matures in September of 22 provides for a loan commitments of $1.25 billion. The facility provides for a borrowings that short term interest rates and contains customary covenants and restrictions.
It is important to note that the credit facility is not secured is not subject to semiannual borrowing base redeterminations and does not prohibit our ability to utilize borrowings for the repurchase and refinancing of our senior notes.
The agreement contains financial covenants that limit the amount of total debt, we can encourage and therefore may limit the amount available to be drawn.
The three financial covenants already know funded debt to cap ratio that may not exceed 60% a leverage ratio under which not funded debt may not exceed 3.75 times of adjusted EBITDA.
And the present value coverage ratio or PV nine ratio under which the present value of our proved reserves must exceed net funded debt by one and a half times.
The present value calculation is required to be delivered to the bag Bank group on April 1st of each year and is calculated using the prior year end Reserve report and an average commodity price deck provided by a subset of the bank group, we delivered our present value calculation to the bank group in early March and as of April 1st the PV nine ratio is that.
Most restrictive of the three financial covenants with respect to our ability to incur additional indebtedness and we expect us to be the case through the remainder of 2020.
The next time at present value calculation is due to be delivered to the bank group is April 1st 2021.
We are currently in compliance with all covenants under the credit agreement.
On the liquidity front, we exited the first quarter with over $300 million of total liquidity made up of $70 million of cash at approximately $240 million of incremental indebtedness allowable pursuant to the PV nine covenant as defined in the credit agreement you can find more details about our liquidity position on slide 12 of the IR.
Okay.
We believe that the generation of free cash flow cash on hand, and the expected AMTI credit refunds will be sufficient to fund our operations capital expenditures interest expense and repayment of the $332 million of notes due March 1st 2021 over the next 12 months. In addition, we expect to have access to borrowings.
Under our credit facility to address any additional liquidity needs that may arise during that timeframe.
On the liability management front, we continue to evaluate our options regarding our debt structure. While we don't have a specific plan to discuss today, we're closely monitoring the market I remain engaged in constructive conversations with their bank group bondholders and other investors about their views regarding our capital structure going forward.
As I discussed earlier it is important to remember that our debt securities. Both our credit facility and senior notes are structured substantially different than the majority of our peers and as a result, our strategy may look different than theirs. We look forward to updating you on a plan that makes sense for all of our stakeholders on future calls.
Moving on briefly the guidance as stated in Yesterdays release, given ongoing uncertainty continued market volatility on the potential for both voluntary and involuntary curtailments over the next few months the company's previous 2020 guidance should no longer be relied upon and further guidance aside from capital investment guidance has been suspended until further.
Yes.
In light of market conditions, we have scaled back our capital investment program by 32% from our original 2020 guidance.
Excluding acquisition and divestiture activity the midpoint of our guidance is now approximately $385 million, including capital for midstream infrastructure. The Permian basin will be allocated approximately 75% of the total capital budget.
As Tim mentioned earlier, our original plan was front end loaded so based on our updated guidance. We currently plan to spend approximately $200 million for the balance of the year, but the bulk of that forecasted to be spent in the fourth quarter, assuming we see the necessary price recovery. Please see our earnings release for a few additional details on a 2020 guidance with that.
I will now turn the call back over to Tim.
Thanks, Bill and it will just go straight into a acuity.
Thank you.
At this time will 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 total indicate that your line is in the question Q.
You May press Star too if you would like to remove your question from the Q for participants do you think speaker equipment. It may be necessary to pick up your handset before pressing the star keys.
I get asked the question Press Star one on your telephone keypad, you will pause for a few moments the pull for questions. Thank you.
Our first question comes from Kashy Harrison with Simmons Energy. Please state your question.
Hi, Good morning, and thank you for taking my question.
Yes.
So first one for me I was just wondering.
How much production are you, a currently curtailing and and and Bill I know.
Your ability to comment on guidance is highly limited just given the uncertain market, but I was wondering if you know either one of you could provide a best guess on how to think about an exit rate for 2020 out before trip.
Yes so.
Let me, let me take those two questions the separately and I'll start off with the.
Kind of talking about 2020, and then going a little bit about 2021.
So you know if you look into how we're doing and you saw the chart. We provided on the issue of 312 and.
You know that's nothing has really performed and built up to about 30000 barrels a day and in March we will peak production and plateaued around 65000 barrels a day net to the entire business.
If you then.
Outside of shut ins assume that we don't want to decline, which we started to go on a we would we would assume kashi that our exit rate will be about 45000 barrels a day.
And I'll put a little bit more color on that so.
So I know a lot of people are curious about what is 32% reduction Catholic studio volumes.
If we werent pacing to shut ins and we were providing guidance. We certainly would have expected without the shut ins or 32% reduction capital would have taken about 10% of our volume out for 2020, Oh, it would've been hard but our through 12 that outperformed the so we're going to come in little bit.
Heart.
Then.
You know what then you have to consider shut ins right now I think we'd have about 3000 barrels a day shut in I'll talk a little bit more in a minute. So that's going to be a little bit long answer because I think you answered yes. The what a lot of people are curious about but yeah. We'd expect some more shows going forward and I'll go into.
And a little more detail. So if you think about what does all this name for 2021.
So when we had our to your updated forecast for the reduced capital and I've mentioned that we expect the lower production by about 10%.
In 2020, I think if you assume that carries forward into 2021, what's kind of flat 20, 2020 or 21 production I think that's a good ballpark to be in but of course, there's lots caveats around wells were assuming that price recovers. So the level, where we can start fracking again in the in the fourth quarter.
We've got that going on in November and so we need to enter the year on a on an inquiry. So last year. We ended the year, we were a reduction reducing through the first quarter. This year, we entered the year on on an increase but however, you look at that.
And however, you look at shut ins, we think kind of 45000.
Barrel a day exit rate is pretty good.
So let me let me now I'll turn to the question on kind of the shut in because this is one of the more complex thing a that the entire market is wrestling with and as I mentioned in the prepared remarks, you know once the netback price is equal to the variable cost plus transportation or any particular oil.
No.
We will consider shutting in that well, but we're also looking at the taking into account clinical considerations and also leasehold factors.
There's a for instance.
We have to the new wells and no through 12 tanks there the over their bubble points that would be an example of a well we wouldn't want to take offline, but it's also an example of a well has a very very low operating costs in so it'll be one of the last you off anyway.
We're also.
Factoring in kind of cost to return wells to production after extended shut in periods.
So you wrap all that together and you say $15 oil price.
And netbacks ranging from three to $10 barrel, depending on the a specific field differentials, we think it or $15 same price, we'd anticipate shutting in about 20% of our total production.
Majority that coming from the Wilson with about 60% or the Wilson shut in.
Ill finish by telling you that may is a bit of an anomaly and so we're just looking bus on an individual well basis, we sold the physical barrels for me.
And so if we have to a place that we shut in them you have to satisfy our contracts we have to pay a fee, which stood the update spend dollars barrel to satisfy those contracts. So in may we have to consider that.
We would not anticipate this point, having a significant shut ins and may but as we get towards June a price stays where it is.
Differentials, hopefully coming a little bit the role comes in a little bit and were able to sustain production, but we're prepared to shut it in its not so that was a really long answer but I think it gives you I guess a number of folks on the phone and answered the questions on People's minds.
Oh, that's very helpful and I'm assuming.
When you when you talk about that 45000 barrels a day exit rate you're assuming some of the production that gets shut in that the some of that production comes back is that the assumption there.
Yeah, I assume all of it comes back you know we it doesn't take a lot of movements were our wells.
On the calculation I mentioned are delivering good EBITDA and so you know if we if you look at Ford strip, it's off waiting in the mid Twentys the mid Thirtys out in the fourth quarter.
And we we would anticipate being a good shape to be bringing those wells back home and certainly if we saw prices in kind of the mid thirtys, we'd be encouraged to start or activity again.
Yes, the one one of the only thing I want to kind of add to that sorry is that we're doing this independent of our hedge position I know some operators talking about I'm talking about barrels above the hedge position. We think this is should be an independent decision.
Absolutely the hedges financial instrument and we're looking at every individual independently and if it's losing money, we shouldn't be producing it should be saving the transportation and operating costs.
Well that but that certainly makes sense.
And then I guess for my second question, you know bill Thanks for all the calling the balance sheet. So given the unsecured nature of the facility. If you wanted to say issue.
Second lien or third loan notes.
Similar to what some of your peers are trying to do.
What would need to happen would you need to transition to a secured facility first and then issue it or do you do you have the capability the issue subordinated second lien thirdly notes to date and take out the up the maturities that exists you know in 23 and beyond.
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What do you go ahead.
It's a good question Koshi you know the answer is we don't have the ability to issue or limited ability. The credit facility has a a small basket under it but it's very small and then of course the notes going the other way have a basket a limitation on these basket as well under the indentures that would limit the size of the credit facility. So that we that we'd have to.
He created we're having conversations that you know as I mentioned with our bank group and bond holders and others I'm just to see the best path forward, but as it stands today, we couldn't go out to answer your question with an example, we couldn't go out an issue half a billion dollars of second lien notes today, let me something like that could happen we'd have to modify some things in our capital structure.
Okay. Thank you.
[music].
All right. Thanks.
Our next question comes from Neal Dingmann with Suntrust. Please state your question.
Morning, Tim just a couple at all done on the said I just want to make some color on this how do you view.
When you think of sort of full shut ins versus material curtailments, and then sort of the second part of that you anticipate much in the way of cost to bring new shut ins back.
[noise], Yeah, we we have a factored that in and Oh hit the kinda costs have returned to production first and we kind of prioritizes shut ins and go about or different categories and kind of the easiest one to turn on an offer our gas with wells not a lot.
The mechanical moving parts are rod pump wells, we would say on average about $15000 well, it's a cup of $50000 to repair a part of processing as well and so we think about wanting for could habits and so we're we're putting in about 50000, well, but yes fees gets to be a lot more problematic. So we would actually slow.
Our our he is fees.
Substantially before shutting in them.
Replacement of any SP and work or were there could be 250000. So yes, we're considering that as we go.
You know I would consider what we did all 11 25 is curtailment.
Right now or production you know that you know that the US you should be probably.
Hitting you know we just closed 10 wells that are shut in.
At a conservative level of thousand barrels a day elsewhere quite a bit <unk> oil shut in there waiting for a bit better price.
And so we're going to be we're going to be smart about this we don't think this is where this forever. We hope it's kind of.
Three months a phenomenon, but we're prepared to go lower for longer and then if it looks like a longer same period, you're probably more willing.
To shut in obviously fully and keep it down and pay the cost spring, but we want to be smart about this and balancing.
Got it and then just one follow up for you just on the DUC Count I'm, just wondering where Ducs now and then where do you sort of see that.
I mean, obviously as you take a break up on the on the Frac spreads that are part of the year. How do you. When you were kind of given that kashi debt sort of production. How do you think about ducs today and will that sort of where will that be towards the latter part the year.
Yeah, I think you know, we Fracked I think 11 wells 11 25.
Before we before we shutdown fracking and so we probably had another 14 wells to go there there were already drilled but uncompleted.
And then we notified the second rig.
Yeah, but a month ago left on April 24, so it probably drills. Another couple of wells and then if you do the math on every couple of wells a month for the break this drilling.
Probably getting a pretty good sense or we're going to be on DUC count as we get back in November.
If we get back to busy in November we'd also pick up a second rig at that time, we've got the money and the in the cash flow forecast to be able to cover.
Both fracking and <unk> and the second rig. So you know I don't have an exact number on the DUC count will be at that point, but.
The technical team assures us that that's enough if we pick up the second rig to get started in November and go where the continuous program.
Very good thanks for the details.
Okay. Thanks.
Our next question comes from Derrick Whitfield with Stifel. Please state your question.
Derrick Whitfield your line is open.
Thanks, Paul.
Hello, Thanks, Good morning, all.
Yeah I wouldn't here.
Good morning, all perhaps perhaps for him.
Are you a tripling the supercharge reservoir condition, so wait to decrease closer space and are there other design factors at play.
No I mean, that's typically what we've seen in Mustang Springs.
Yeah, we had a situation here where.
We you know, we we were able to go and do 25 wells back back. So you know those those first wells were you know we started pressuring up and they.
Frac across we were going kind of from the east and west.
They're getting the influence all the way through that of that Frac program and so that's generally how that but the tank designed to perform Oh, we attribute the better performance to really our strategy around limited venturian.
And getting a higher fresher each of the perforations I'm getting a better fracture.
Network produced and so when you look at I can't remember the slide eight we show that charter a chart on cluster efficiency, we find that to be extraordinarily encouraging and how do you think about cluster efficiency in the path.
From 60% to 100% and now you're getting up into the 90% average on cluster efficiency, you're breaking dropping a good contribution from all of that Iraq and so you know were quite encouraged by that but that's that's an important thing and that's also why.
We want to really keep a close eye on on vs. You have and 25, we were comfortable keeping that shut in for two to three months I think after that we show a less comfortable because you do have production offset and you could see pressure coming out of tank and could start to potentially impact that you are so you know we're keeping.
And that this new territory for us, but we do have the ability to to Ah checked pressures on wells are shut down and so we're having what that gets a form where we have a concern.
And Tim just to clarify the on that last question the cluster efficiency, our you're attributing that improvement due to decrease cluster spacing.
That was really the heart of that question my apologies.
Yes, I'll say, one thing and I'll turn it over to a job right because the elite technical or but but it's the combination of the person size.
Fewer perforations and then a cluster spacing density, but let me turn it to Joe to give you a little more specific.
Yeah. Thank you for the question Tim So when we think about that cluster efficiency in driving that up we're really looking at kind of some key variables. There we look at how we space the corporations and the number of perforations in that Frac stage. So we're we're driving for that kind of high perforation friction.
That will ensure that we get a good distribution of frac initiation throughout the number of holes, we put in the pipe. So we do that with combination of again whole size, a number of bowls and our pump rate, which all works together to create.
Create that.
Deficiency.
Great. Thanks to the detail on that and then as my follow up switching over to the Bakken could you talk to the drivers behind the improvement and you're actually year over year.
Yeah, I'll turn it back to Joe as well because these are probably not as well.
Alright. Thank you yeah, R.L. or we are in both areas actually has been an area of focus for us over the last several months, you'll notice, it's kind of year over year and a quarter over quarter, we continue to see improvement there.
In the most recent days that's been through an effort to really high grade or Workover program and I'd say now were I'd be an extremely selective a with the expenditures on Workovers and we've also taken a pretty hard look at contract labor and and ways to bring things in house and a and then kind of lastly, right now we're working with all of our view.
Tenders and suppliers.
And there and they're working with us as well on cost reductions as we kind of continue forward, that's definitely a team effort and a in a field led initiative for us to bring those costs down.
Thanks for your time guys, great update in a very challenging market.
All right. Thank you.
Our next question comes from Josh Silverstein with Wolfe Research. Please state your question.
Yes, thanks, good morning, guys.
On the.
The herds are coming up and then the payments or sorry, the retirement that you made in the first quarter.
I'm just curious what your outlook for free cash flow over the back half of this year and you're not still trading well below par I'm. Just curious if you will just continuously be out in the market buying those back in that potentially would you like even think about drawing down a 100 million on the revolver to go and do that.
Turning out to bill.
Hey, Josh I'm. Good question I mean, the answer is everything is on the table you know well obviously, we in the fourth quarter and first quarter, we were able to purchase or some notes on the open market you know whether that opportunity. There is there again and you know going forward, we don't know, but I mean, certainly it's something we'd consider I'm you know and again as I mentioned in her prepared remarks.
And my answer earlier, yeah, everything is kind of on the table, we're having discussions with with everyone. A banker bondholders et cetera, and you know we look forward to a you know discussing our plants would you guys more going forward, but everything is on the table at this point.
And then just on the on the operational side you see things here. One you know Tim you mentioned in your comments that you hope the Permian activity can come back when crude oils in the end that made the mid thirtys.
We don't really hit 35 upward curve until the end of 2021. So does that mean you guys. They had no wonder next piece right right right now in and just thinking about the activity restarted November is that something that you contracted already or.
Do you call somebody up in a couple of months from now they have you wonder what's your best price and how do we go from there.
No there was a good questions and again, Josh you can imagine we're in kind of middle of the firefight right now I think we've done a good job getting down to a good run rate we need yeah, we're going to let the we're going to we're going to watch and see how 2021.
You know develops I mean, if we would ask me six months ago, when we deliver 100 plus million dollars of cash it.
Our pricing scenarios I might have said no and so will you know I don't want to lock is in the same couldn't pick the activity back up but we're going to be cautious to make sure that we don't go into into a large outspend position in 2021, So we'll keep modifying up.
Contracting the the the the equipment on the and the suppliers.
We're confident in doing that we've had a longstanding relationship with halliburton on our or Frac crews, we use a unit drilling on the rigs have rigs and crudes available and we feel comfortable I mean, we're down to a fairly small operation.
Good relationships and they're working with US. So we think we can provide had been a notice and get going pretty quickly I asked that question to.
Chris long roll, our head of drilling and completions, probably weekly and he said we're standing ready. So I think you know as we see things improve hopefully you know as we met of snow, what's going to happen as people shut in and then we start seeing that real effects of the fracking a slowing down a bit as.
Mark It comes in balance I think really is poised and positioned as well as anybody to get back after it and thing you know probably the the practice, we had last year going into kind of a cyclical program I think it's helped us quite a bit to think about how do we make sure we retain the right people and equipment to.
Shutdown and pick back up with a pretty short lines.
Great. Thanks, guys.
Okay.
And just to remind everyone if you'd like to ask a question at this time a press star one on your telephone keypad. Once again to ask a question press star one on your telephone keypad.
Our next question comes from Gail Nicholson with Stephens. Please state your question.
Good morning, Thanks for taking my question I'm curious when you look at the hedge market and 21.
Talk about what you're seeing there if anything has changed kind of a standpoint, and then look what do you do there and they use that locking in how did that you guys to do so.
[laughter].
Yeah, we're not seeing a lot of different than normal as far as liquidity is just a matter of what do you want to start locking yourself into for next year. Thanks, obviously over <unk> across the industry liquidity I mean across the industry hedging activity is down a the as Josh just mention them into forward strip event here in the.
Twentys is not encouraging you to try and lock in when you're when you have or kind of an increasing price projected in the court strip and so you know, we're we're making sure that were honing in on.
Being held off right. If we don't have a bigger hedging opportunities are we hope they do come are poised to move fairly quickly on that but at this point I don't believe we would expect to have on liquidity issue. If we try to try to jump in but something we we have a risk committee and we talk about every week, we're being smart about that were.
Certainly with improved prices on natural gas, we've been pretty active and getting 21 unlocked and little bit more but on the oil I think it's it's a little more wait and see at this point.
And then I'm just.
For the question I'd tell you when you look at the fixed versus variable cost and I'll leave it there.
Oh, and the Wilson versus the Permian I can you just talked about how that Barry.
Yeah, I'll turn it over to Joe to talk about that distribution.
Yeah. Thanks for that question. So when we think about our fixed cost versus the variable costs you were.
That variable cost bucket, we're looking at things it wouldn't be directly related to the cost of production that might include things like chemical a water disposal generally utility power or things like that and so there is some variation between areas and as we're making those decisions we actually take it all the way it to the end.
<unk> well level. So we kind of start my thinking at the at the Big picture field level than we dial it in all the way down to the specific well, including the.
Contracts and transportation that are directly connected to that well so.
Your fixed to variable a breakout variables between the areas, but and across the wells and generally the variable cost is a little bit higher than that fixed cost when you add the dollars now.
And when you look at the variable cost what what I guess pieces of those variable costs have you seen them not I guess deflation.
Yeah. So you are the ones that are that are in our direct control like water disposal. There tend to be just kind of direct operating cost. So those are pretty stable near the other things that come through.
Various vendors and suppliers like chemicals were working with them to bring those costs down and we do bid there was kind of services out in that.
And we're doing that actively right now and seen some some movement in that front.
Okay, great. Thank you.
Yes.
Thanks Gail.
Thank you no further questions at this time I'll turn it back to Tim cut for closing remarks.
All right. Thanks, everyone. Thanks, and good questions and really I don't have a lot more say I don't want to reiterate what we just went through but I do want to take the opportunity.
Two sincerely thank our workforce you can imagine a the stress of hitting home.
Having they figure out how to social distance in the field safely and we continue to do that and I really want to thank directly or field employees are showing up everyday delivering a fantastic service and keeping the positive attitude as they do that we're checking in with everybody on a very regular basis, we have a field superintendents our leadership calls now.
And I participate in are listening to our drilling a folks and making sure that every single thing. We do is safer employees. Our contractors are but our employees. Just flexible you can also imagine when we asked them to fundamentally do a business plan in a matter of a couple of days to execute.
Reduction of activity that both through we're able to review that quickly with the board and say good action. So I'm also proud and very confident and you know this is.
Number of its been doing this for a while this is one of the horse we've seen but we're very very confident we can navigate a timely and just move through this so without I think we'll sign off and the again, thanks for your interest and selling it.
<unk>.
Thank you. This concludes todays conference all parties may disconnect have a good day.