Q1 2020 Earnings Call
[music] greetings and welcome to the.
Being energy 2021st quarter financial and operating highlights.
At this time, all participants will be in listen only mode and the brief question answer session will follow the formal presentation.
If anyone should the car operate assistance during the conference. Please press star zero from your telephone keypad.
Please note this conference is being recorded.
I will turn the conference over to Mr., Tim Rochford Chairman of board of Directors at Ring Energy Mr.. Robert you May begin. Thank you operator and welcome all those first two or 2021st quarter financial and operations Conference call.
Tim Rochford Chairman of board.
Joining me on the call. This morning is our CEO Kelly Hoffman, President, David Fowler, Randy Broaddrick or CFO.
Danny Wilson executive VP and head of operations only Lamb VP of engineering.
So bill Parsons or Investor Relations.
Today, we're going to provide a quick concise overview of the financial and operational results for the first quarter.
And as we did on our year end 2019 conference call, we'll spend the majority of the called the identified discussing and summarizing the factors that directly affect the current and future operations of your company at the conclusion of the first quarter review will turn it back over to the operator for opening up questions to the list.
Well this time I'm going ask Randy Broaddrick, our CFO to give us a brief overview of the activity financially in the first quarter Randy.
Thank you Tim.
Before we begin I would like to make reference that any forward looking statements, which may be made during this call or within the meaning of the safe Harbor provisions of the private Securities Litigation Reform Act of 1995 for a complete explanation I would refer you to our press release issued Monday may 11th.
If you do not have a copy of the release one will be posted on the company website at Www Dot ring energy Dot com.
For the three months ended March 31st 2020, we had revenues of 39.6 million them.
Net income of 43.8 million.
And earnings per diluted share of 64 cents.
This net income included a pretax unrealized gain on hedges of 47.1 billion.
Without this unrealized gain after the effect of income taxes, our net income would have been 7.2 million or 11 cents per share.
It's unrealized gain is recorded because the value of the derivatives changed as a result changes in oil prices.
During the quarter, we had 23.9 million and net cash flow.
And 16 million and capital expenditures for post Capex positive cash flow of of approximately 7.9 million.
The three months ended up we had sales of 855603 barrels.
Guess sales of 795005, 1500, 51 Mcf for a total of 983195 be a week.
I received prices were $45 in 16 cents per barrel of oil.
<unk> and 22 per Mcf of gas.
For an average be a we price of $40.25.
On prior conference calls, we have make comparisons of our current results with the prior years results for the same time period.
We have refrain from doing that this time in order to spend more time on current events.
Those comparisons are in the news release put out yesterday.
Before I turn it back to Tim I'd like to highlight a few key points that I believe are major factors in our ability to operate in the current environment.
For the first quarter 2020, we had a pre tax realized gain on had just a 3.3 million that's realized versus unrealized for.
This amount was received in April for March hedges.
Just we haven't place our financial instruments, and we will be paid based on the hedges, we haven't place versus the index price regardless of any actual production or sales.
We do not have to have matching production to receive payment on the hedges.
The spring <unk> Redetermination on our credit facility is in process. We have provided the bank group with the normal information, we generally provide including updated reserve information.
We are currently in compliance with all covenants of the credit facility.
The redetermination should be completed within the next few weeks.
We had an opportunity with some of our vendors to receive discounts on outstanding invoices in Rupert return for paying those invoices up to current.
As such we drew $21.5 million on our credit facility in order to make those payments and in return we have saved over $2 million.
As most you're aware we filed an S. Three recently this was a shelf registration.
This was done because the shelf registration we had in place previously had expired.
During has always kept a shelf registration active as we believe is it is prudent to have that availability if needed.
The company does not have immediate plans for use of this shelf registration.
With that I'll turn it back to Tom.
All right Randy. Thank you when asked Kelly, our CEO to give us a.
A brief overview of the activity over the first quarter.
Thanks, Tim.
As Tim mentioned in his opening comments here, we feel it's very important to minimize the time spell the call redoing our first quarter.
And and a you've already heard but there isn't really.
Describing in detail and financial operational results from first quarter that was put out yesterday and as Randy mentioned earlier, if you have not seen it a copy of that's available on our website and bring energy Dot com.
Now we've been experiencing.
Now no no really everyone. It's been experiencing every operator is experiencing right now is an unstable and treat.
Predictable pricing and storage dilemma.
Because of lack of storage capacity, there's a large differential between W.P.I. spot pricing and actual price a buyer is willing to pay or wellhead price.
Until the markets, improving and we began to see.
Yeah, the world economic sense at work again, we have to be prepared for this continued uncertainty and before I turn it over to Hollywood. Danny you give you a little more color on several of these items. There's a couple of things I want to point out first of all let me address the Delaware sale.
Which as many of you know, we previously announced or that we had entered into a P. I say in April and the buyer has now started required due diligence we're continuing forward with the answering questions and field visits Biggs all that nature as they come up.
Closing is still estimated to be in June and we plan to use the proceeds to reduce our outstanding debt once we close the transaction.
I'm also worth mentioning is that we continue to cut costs you heard Randy mentioned that reduction I don't voices things that nature, but we've gone over and above that besides us already.
I'd be very low cost operational company in general we continue to reduce DNA, we continue to redo sell a week and especially our capex across the company and we'll continue to cut those costs as we are able and as needed going forward.
And with that I'd like to ask Danny our executive Vice President operations, All your VP of engineering to walk you through other steps. It. We're currently taking that we believe are necessary to ensure our ability to not only weather. The storm that's come out a stronger company in the and.
Danny.
Alright, Thank you Kelly I appreciate it.
Let me start out with just a real quick recap of our first quarter operations for the quarter. We spent as Randy mentioned about $16 million in Capex.
During that time, we drilled four wells and perform nine rod conversions. The drilling consisted of two one mile into one and a half my wells on the north West shelf.
The average IP on these new wells was over 600 deal we per day.
And although our total production for the quarter was down slightly from Q4, we were able to finish with a higher exit rate.
It was 11474 net Boe per day in March versus 11270 be OE in December.
And this is what the only drilling four wells in the quarter.
Little bit of Lumpiness. There is just caused by timing nothing else.
Using our new Frac procedure in our refined drilling and completion techniques. We started using at the beginning of the fourth quarter, our new wells continue to exceed our type curve and our expectations.
A in a few minutes I'm going to address our current operations and our future plans, but for now I'm going to turn it over to ER to our Vice President of Reservoir Engineering, Holly land to address if he wishes.
Hi, This is Hollywood I am I am color I am I touching base on an article that was published late last week and reinforcing how we like our reserves. The article made a first assumption that all seen andrus about are the same everywhere in the Permian basin, there's a great variation in thing I understand positioning environments.
Across the Permian Basin.
And amongst the individual basins and platforms that are sub groups within the <unk> Permian basin. These different environments result in different rock with different reservoir characterization, such as pay thickness Permian permeability and prostate to name a few.
Our lateral lengths of our wealth that we have completed to date vary from 1900, and 29 feet to 7088 feet. Our type curve. It's 5000, an 80, which is an effective one mile lateral.
We we derive our thing Andrew just horizontals from two independent geologic areas with different depositional environment, having very different pace take misses that range from 500 feet to 100 feet. They contain multiple spacing options multiple benches, and we have completed them.
Various technique.
How do you make the assumption that all wells are equal.
[noise] only 6% of Harwell IP on the first day of them out based on what we've done thus far.
Using public data one would only observe the highest recorded month.
Which means 94% of the time, a 30 day IP drive from public sources would be wrong.
Therefore, there are some sense are correct, 6% all the time [noise].
Assuming their math is correct, 6% all the time.
We can then focus on type curves, which are not solely a function of historical data. They also include what geological region. They reside in the pay thickness lending is down how we evaluate the landlines down <unk> percentage of lateral in zone. The length of completion type of completion and how we bring on our initial.
Oh production.
As far as their assumptions on the reserve reports there are many assumptions that go into reserve report, except where we are we have the data. So that the assumptions are are at very calculated. They include Ela, we differentials working interest net rent.
The new interest non operated properties on timing P. D N P cases, recompletion not opportunities and many others.
Our reserves are independently reviewed by a third party engineering company that is very loud cawley Gillespie in associates began serving the oil and gas industry over 50 years ago.
And has continued in on interrupted business throughout the decades and today delivers professional ethical reliable engineering and geological surfaces for the petroleum industry.
They have major clients, such as Concho GE financial Wells Fargo.
Yes, Morgan Stanley and Conoco Phillips, but they have hundreds of both public and private client.
Hi reserves are also revered twice a year by or syndicated bank grapes, which all have in house engineering departments. All data that has entered into our database it independently examined by internal and external auditors.
As Danny mentioned as of the six wells, we I paid in 2020, all of them more northwest shelf wealth and they had a range of I P. S 438 be a week to its highest 813, yeah. We pray day with an average of 558 Boe per day.
The four wells that we completed in Q1 2020 had a <unk> average IP over 600 Boe per day, our type curve, it's 400 Boe per day.
This year, we have exceeded our type curve on every single well that we have drought.
We have stated on various occasions that are I P is our statistical and that there are going to be better in worst areas.
But what I think our 2020 drilling has demonstrated is that we've hit the sweet spot in the northwest shelf and we're excited about getting back to drilling when the market is ready.
[noise], Danny with that I'll hand, it back to you.
Alright, Thank you Holly.
I want to add just a few point of emphasis on what Holly's has to say first it's extremely difficult to adequately pro forma reserve evaluation based on public publicly available information only there's just too many assumptions there have to be made.
So every year, we have a small army of professionals, whether its third party engineers.
Engineers at our banking <unk> at our banking syndicate.
The bankers themselves are independent and third party auditors and our internal auditors that review our information every year twice a year.
These people have full access to our production reservoir geological land in financial information and they reaffirmed our reserves twice per year every year since we've been in business.
In the third point I'd like to make is much like someone who claims is something isn't about the money. We always know it's about the money.
It has been my experience it when somebody claims that they don't have an agenda is the case with this recent article we always know that there is an agenda.
And with that I'll move on to our current and future operations.
Beginning in mid April at their request of our purchase or Phillips 66, we began curtailing production on the north West shelf from a little over 7000 barrels a day down to 6000 barrels a day.
They like every other purchaser were concerned at the time about having adequate storage.
But also wanted to keep enough oil flowing to meet their needs at their borger refinery.
Based on the crash in oil prices, we saw at the end of April we proactively took further steps to lower production outside of the Delaware to near zero.
By the 26 of the month.
Starting about a week ago, we began turning on some of the wells that are reduced right with the goal of producing enough world to show production on every well in the CBP in north West shelf. During the month of my currently we are producing at about 15% to 20% of normal production capacity exclusive of the Delaware.
Oh, we're accomplishing this by turning on a few wells at a time letting them produce long enough to show production and then shutting them in and turning on another said wells.
In April when we started shutting down the wells, we went through a process of pickling the wells with chemical and which include a corrosion inhibitor paraffin control and scale inhibitor. This was done in an effort to ensure that we had the least amount of trouble when we restart the wells.
This process will be followed again each time the will shut in until prices recover enough to bring the wells back on <unk> on full time.
As for holding the leases under our existing wells, we feel that we are being proactive and satisfying our lease obligations with our current strategy by showing significant production from each well each month and then sell in the oil when it makes sense.
On our Undrilled acreage, where exercising options, where we can and negotiating with the mineral owners for extensions on the remaining acreage and so far this has been working out quite well.
When the time comes to bring production back to full speed. We feel this can be accomplished over a 10 day to two week period.
Rod pump wells can be turned on at full capacity with no problems.
But he is fees must be restart is slowly and then sped up over a number of days until they can reach full capacity again.
As for our pricing required to bring production back on a <unk> just like everybody else, we're monitoring prices and differentials daily.
We believe it makes the most sense to turn the wells back on to full time production. Once we see a sustained pricing in the low to mid $20 per barrel range.
And that's at the wellhead inclusive of all differentials and transportation costs and I just want to remind everybody. That's not a one day event that is an average across a month, we get paid on a monthly average.
So we say that we need to see sustained pricing there $20, because we don't want to get caught in a w. shake type pricing scenario, where once prices get back to a point everybody feels comfortable turning their wells back on that everything comes back on to full production not just us but everybody else.
And all of sudden we're back into as a storage capacity issue again, so we want to see that pricing sustained over a period of time before we're willing to bring our wells back on full time.
Our purchasers are anxious forced to come back online as soon as possible.
I have daily and and constant communication with our buyers are the purchasers are being very creative with the idea is to give us some guarantee a price stability.
We've had several discussions with opera was purchasers that as you know what price do we need to be yet and they're looking at the possibility. If we can reach that point at sometime during the month they will go out.
And and secure pricing that will allow us to have stable prices for the period of time, whether it's a month or are you know two months whatever the price the whatever the case maybe.
But in all cases, they are extremely I'm anxious for us to get back to production.
[noise] as for drilling we feel I appreciate prices need to be in sustained in the mid 30 range.
Again inclusive of all differentials and transportation costs.
At this level, our economics, particularly in the northwest shelf become attractive with our internal rate of returns in the 70 plus range and our discounted our allies of approximately two and a half to one.
As Randy mentioned too and it's in the press release, we have amended our capex for the year as you've seen we've we've reduced its $25 million to $27 million with roughly 16 million of that being spent in the first quarter. A the range of spending is to account for the unknown timing of returning wells before.
Production.
And doesn't account for any drilling for the remainder of the year.
This lower budget emphasizes our focus on maintaining free cash flow, while still being able to form the critical tasks needed to maintain the integrity of our operations.
Even though we are producing at a significantly lower rate, there's still work to be done.
With the Clinton, we plan to continue our program of converting wells for me as piece to Rod pumps is needed typically this will be done when a well when and if a wealth sales and we also continue rightsizing our E. S. P is when it's appropriate.
We're seeing tremendous progress and lowering our equipment failure rates as we go through this process and thereby lowering our el away in future capital need.
With that I'm going to turn it over to our President David Fowler.
Thank you Danny and over the past several weeks [noise].
I've had a number of conversations with middle to operators, representing both independent and private equity backed management teams to just get it gives us gauge what percentage of their production volumes that shut in or curtail.
To private equity backed management teams I spoke with had at both had exceptional hedge books and really only had minimal production cuts one had to shut in of approximately 20% and the other one was about 5%.
Now the majority of the independent producers I spoke with reported shot at 100% other production all remark the selling a barrel of oil for single digit oil price, which is simply giving it away.
And most of those run hedged of course, the independents that we're still producing but on a limited basis had a few leases with extraordinarily low lifting cost and were able to continue to pump those wells profitably there maybe some exceptions, but the independents are shut in all of their production. This whole voluntarily due to the oil price and weren't necessarily crew.
Tail bother purchasers.
And interesting insight from an operator.
Not a holding high regard sure that the rapid pace of shut ins and across the Permian basin and other basins have been so significant but it is caught some oil purchasers long other nominations and that they are now coming up short on barrels as a result, there are reaching back to producers with a stronger wellhead oil price to get more barrels upload.
Away.
Based upon my limited conversations.
It seems to indicate that the magnitude of the shut answer curtailments by independent operators across the U.S. could be substantial and May mirror, the 1 million to one of the half million barrels reported by public companies to date, if oil prices at the wellhead stay sub $20 a barrel shut us we'll probably continue through.
We may and June.
And it may prove out that the two and a half to 3 million barrels a day that has in fact been shut in or curtailed across the U.S. could have a positive impact on the speed at which the market rebellious its worst time will tell.
On the M&A landscape.
We anticipate deal flow to be robust between now and year end and its companies seek to consolidate with peers that have leasehold positions in similar geologic plays.
The motivation or purpose is to create a stronger better financially position DMP. So when the energy supply demand picture improves there will be far better off but we stay attentive to what's going on in the market in our core areas. Our primary focus remains staying on strong financial footing. So we can successfully navigate the ball.
Utility in today's market.
And Tim I'll turn it back to you all right David. Thank you I'm, just going to make a couple of comments before we turn it over to the operator. So I think it's important point out that as co founder ring energy and chairman of the board I personally want to thank all of our management team all the support personnel for the tremendous job that's been done and this very unparalleled time.
I've been in this business 40, plus years and I've been through a number of cycles. Both good and bad. This management team has worked around the clock examining every aspect of operations. All for one reason the posture ring energy not only to survive but to excel.
We will focus going forward, we will focus our attention on the two excellent assets at hand northwest shelf Central Basin platform. Both of these assets have years of drilling development opportunity I am confident and our ability to become one of the post virus post war or price horses success stories, so with that I'll turn it over to.
Rob or operator, and Rob you go ahead and open it up for questions that we might have for a list.
Thank you well now be conducting the question answer session. If you want to ask a question today. Please press star one from your telephone keypad and a confirmation Tony indicate your line is in the question Q.
Let me press Star too if you like your move your question from the Q.
Participants that are using speaker equipment, it may be necessary to pick up your handset before pressing the star he's.
One moment. Please so we poll for questions.
Thank you.
Our first question is from the line of Neal Dingmann with Suntrust. Robinson. Please proceed with your question.
Well it elevates details Kelly what could try my first question is really on your financials I just want to make some clear.
If you will could I think I've heard this right just want to make sure that typically that you. All when you look at your total overhead that that in fact could be covered with just the financial hedges going forward. This year.
If you could talk a little bit about that and you know it's kind of part of that question would maybe just give some color on <unk> I would lump that in their kind of survival plans in these lower prices. If you could just slumped a you know sort of cost with these Hudson said there.
Sure and they don't you don't look.
Good good question, let me, let me just answer that quickly and then handed over to Randy you don't give a little more color on the short answer that is yes, yes, our hedges will cover overhead going short, but Randy you want to handle more color into that.
Sure Yes.
At a sub 30 prices the hedging does a allow provide enough cash flow to cover our overhead.
DNA interest expense so forth obviously has discussed.
$30 prices unless the differential is out of line would be being bringing production back on but and then at lower WT I prices the hedges actually would generate even more income so [laughter] as Kelly said short answer yes, the hedges would provide enough cash flow.
Cover our overhead.
Very good and just one follow up on the ops, if I could maybe turn it over Danny just it's been over a year now since you guys have been answered in the shelf and I'm. Just wondering how do you think about the latest curves that that played out versus I'm looking I think its slide 11, if I recall in today's slides or prior curves and maybe if you could just give some thoughts on again I know you don't have new curves out.
Just any color you could get around that.
Yeah, No I appreciate that Neil no lift we no the curve that you're looking to add on pay on the slide 11, which is our type curve for the north West shelf. That's it that's one that we came up with when we were doing initial wish bone acquisition and that was our work that we did looking at the wells that they had drilled and then you.
During that as a model going forward and we knew it was very conservative.
We came in and a you know after visiting with some of the other operators in the area, particularly with our friends over its Stuart energy.
No we came up with a very a very different type of frac than we've been doing on the on the Central Basin platform. We also came up with some different types of techniques for completing the wells and even bringing them on production.
At slower rates to avoid things like a the scale issues that have played some of the early operators on the north west shelf.
And by doing that we've seen exceptional results out there.
We've contemplated over you know when when we'll really be willing to update this curve a as I mentioned in my in my talking points, you know that we really only started this a new procedure.
Early in the fourth quarter and I'm, even though we know its successful there's no doubt about it and that we're exceeding the type curves.
Yeah, we did we'd like to have a little bit more history on it before we before we update that curve and not to mention that that curve. Also you know takes into account what we think we're going to encounter as we move out into some of the.
Lesser drilled areas. So no it's kind of a bounce we know we have some really good wells. We had we feel like from our study that we have some good good areas.
Outside of the areas that have been to focus so far but we just kind of on leave that out there.
For the current time.
Even though we feel like we're going to exceed that easily overtime.
But again thank you.
Okay.
Our next question comes from the line or John White with Roth Capital. Please proceed.
Good morning, and thanks for all the detail.
Danny touched on it.
Little bit more explanation.
Differentiated.
Rob.
<unk>.
Well <unk>.
Very easy to restart in yesterdays needing to move a little Hello can you.
Give us some more detail on it yet fee.
Oh, you bet you bet John now that's a great question and that's why it takes a little longer to ramp up in some thank you can just you know you would think you could just go out and turn on a switch and everything just comes right back to normal.
Again, the rod pumps those are a very easy just to turn on they'll come on with no issues and go right back to full capacity or 100% of production and in fact, we've seen that just in the last week. When we've started up our wells we started out by turning on the Rod pumps.
Because they were the easiest and I mean, our production pop right back up in fact, it exceeded what we thought we were going to do that out. So I think we're getting a little bit of flush there, but the is piece or a little bit different obviously, they're down hole.
And you can't just say and we'll get a little bit technical here, but we adjusted the speed of the pumps by adjusting the electric current going down to them a in hurt and so let's say, we started out a well and it's the manufacturable recommend a starting.
Speed.
And maybe that's 55 Hertz, just as a generic number.
And then over time, what we'll do is we'll monitor the fluid level, we'll see what's happening assuming that the wells still maintaining good fluid levels. Maybe every day that again, the the manufacturable recommend that you don't go.
Ramping too quickly, but we can run up maybe another one or two hurt.
We will monitor the fluid level, if it's still in good shape, but will go up another one or two hurt so that and that's what I'm, saying you kind of you have to kind of ramping into those because you don't want to turn it on full speed pull all your production down in all sudden you've got a you know a pump this not moving the right amount of fluid you've got gas interference now.
Coming through and that's what ruins those pumps I will say E.S.P. you do not like to be turned on and off they like to be run at a very cost and speed all the time.
But.
We feel like with our with the procedure that we have in place of starting slow pickling and the big part of this too is pickling the wells as we shut them down.
So we're loading them with corrosion inhibitor, we're loading them with with paraffin in inhibitors were using scale inhibitors. So that is there shut down we don't have a bunch of.
Well some is basically crap junk John [laughter] falling back onto the pump and that's when that's when you have problems as if you have a lot of yeah, let's say sanders scale or something.
Even iron Thatll come down over time, it settles out of the fluid and it'll come and sit down on top of those pumps and then when you try to restart them you have that junk in the whole and that can twist to shaft in a very quickly and so you didn't you just have to be a little bit more careful with it but I think starting at the slow rate.
Pickling the wells ahead of time will eliminate the vast majority of those issues.
Our next question comes from the line of.
Richard Tullis with capital one.
Is your question.
Thank you good morning, everyone.
Maybe a question for for Danny if you could recap gain will.
Shut ins for April what you expect for Bay between Curtailments in shut ins Danny please.
Yeah, you bet now.
As I mentioned you know when we went into a into April you know, what our highest rate that we had for Ah coming out of Q on.
It almost 11500, a net barrels BOE a day, we Philips called as probably maybe the towards the end of the first week of April and as I mentioned, you know they were like everybody else. We were seeing all these reports about storage filling up and and everybody was.
Getting very concerned and they asked us if we would slow down a little bit on the north west shelf.
We discussed that internally and we decided since it Philips is a very important purchase or force and let me just throw this out there in the meantime, not only are they purchase or on the northwest shelf, but now there are purchase or on the central basin platform.
They asked us to to slow that down, which we did and and they were very grateful for that.
And then when we you know when we had the day there around the 20 or 20 or so the month, a net price went minus $35 and we saw what that was going to due to the average pricing for April.
We had a lot of discussions internally and we decided our best move at that time was to go ahead and just shut the production down and we did that across the north west shelf into Central Basin platform. We did leave the Delaware running because we were in the middle of our.
The work, we're doing with the due diligence and what the new potential purchase or on the in the Delaware. So we did leave that going but we did shut down the rest of the production.
Moving into May our goal was to show enough production on each well.
And that we could have you know show significant production on those wells we.
We also at the end of April sold everything we could sell left our storage is empty is we could and so where we have a lot of internal storage right now in our system. So what we did were bringing wells back on beginning the battle we could go.
Producing them for three to four to five days at it and then shutting them back down.
Putting that well putting that oil in storage them, and then where restarting the other one other wells in the area.
So you know I think we at least but anticipate through may that we will see this will be the procedure. So we're producing at about 10% to 15% of capacity.
In the Central basin platform in the North West shelf.
You know, we'll see where the pricing for June what it looks like and we'll see the big Big thing the pricing to not even as important as the differentials when you get the WT WCS differential you get the the senior May roll you get all the all of those components that go into the price.
Thing.
He does all settle around the 25th is a month and so we'll have the process for you know June at least futures prices for June will be set around the 20 at the differentials will be set around the 25th.
And so at that point I think we'll have a better idea what June looks like I will say the differential you know just give you. An example, where we're at today, let's today's prices when I look earlier was around $26, but the differentials for for May are about $12 for us.
So that only puts us at about a $14 price, which isn't enough for us to bring everything back on.
We are seeing the differential shrink a in June and even moving farther out we're seeing them getting even lesser and lesser as we're moving out so.
I don't I don't know when we'll get back to full production, but it is getting better Holly has come and our average differential ever before this this turbulent time had been about $2. So so the $12 that Danny just quoted was by far the most what we've seen in the differential since kind of late late.
18 to 28 yeah.
Okay, Yes, Richard this is that Kelly I want to make a comment in addition to two what Dan He was saying just for clarification.
We're Danny was talking about Phillips asking for curtailment early on and that was important and we cooperate with that in an effort to help.
Staying that relationship there as time has gone on though storage is not the issue for us at this point in time, so were voluntarily I'm doing this as a result of price that's more important us right now, whereas if we wanted to ramp up today.
Storage is available for us we could increase our capacity would you agree with that Danny.
Yes, yes, some facts Philips like I say I have constant communication with them and they would love for us to come back up to a higher production level.
That's very helpful. Thanks, Thanks to all of you and I'm.
Just lastly from me saw substantial reduction in cash DNA quarter over quarter in the in the first quarter.
Randy is that what Kelly is that a pretty good run rate going forward, but should we kind of look for similar type numbers as we move forward.
Yes, I think what on the first quarters is a good run rate for but we'll see for the rest of the here.
Okay. Thanks, a bunch that's all for me.
Our next questions from the line of Noel Parks with Coker and Palmer. Please proceed with your question.
Hey, good morning.
Good morning no.
All right just to your question kind of touched on my my first one a second ago. So.
Modeling out for the rest of year.
Does it seem like sort of that.
$12 differential ranges.
About as bad as we should assume it gets order or do you think worst case.
Here little unclear.
Now that's a great question, Danny I know, we've spent a lot of time crunch in those numbers, what's your sense of that Danny.
You know, there's there's a lot of things that go into that let me start out by saying that in a lot of that is getting the economy restarted, but once once that thing once it gets going but you know the at the market usually pretty smart about a lot of this stuff and what we're seeing as we look out into the feature and I don't I don't have those tables and free.
Joining me right now, but I think I think April was our low point I do think that was the case and I think we'll see things improving through now through the end of the year.
[noise], Danny just to be clear for Nolan other listeners. So by the 25th of this month well know what that differential is gonna be fixed out for June production correct.
That's correct.
Okay, great and.
About.
Rob from conversions and I'm, sorry, if you took them earlier Tonight.
I just missed.
Where do you stand relative to your overall inventory.
Both converged offerings.
Roughly what share of goes that you plan to do our are already done and how many still lie ahead.
Yeah, So we've probably done about a quarter now of our wells.
And again you know, it's it's a matter when the wells reached the fluid production when that bond that production drops down to a point, where it makes sense and again, we what we typically do is we'll wait for the SP to fail in NIM will come in and do the Rod conversion.
You know we have really in a and I've said this in at some point will will we may even put some slides in the presentation about this but you know we've lowered our failure rate from over what we call one onetime per year per well.
So going back in historically before we started doing the rod conversions.
Well tip, well loyal a well would typically failed somewhere around six to nine months.
On a consistent basis and what we've done now as we've lowered that down to a point were on average we're averaging a little over almost two years before between failures now that there's a lot that goes into that.
But that's just an example of what we've been able to do by following this program and again. It also goes back. So that's lower you know that lowers the failure rate means we're pulling fewer wells.
But it also we lower it would tremendously lowering feature pulling cost.
Typically you know will spend 150 to $170000 pulling the.
And he is P and replacing it versus a about we've been averaging about $30000 a job on the rod when they go down so tremendous savings for us anello future elderly and we see the same kind of response, even by when we start out with very large dsps.
In these wells because we're moving a lot of fluid initially and then over a period of time as the fluid level comes down if that larger pump sales, but it's also but it's not quite ready to put on rod pump will run into smaller SP. That's much more efficient at those levels and that all this plays in two to the best I mean.
It's a tremendous improvement in our failure rate.
Great. Thanks, and I just wanted to double check the the types you have in the slide deck that show the IR are different.
Price decks I forgot the the shelf and a greater platform.
Those numbers I'm trying to remember our those also at hearing to your your original type curves are those better informed a little bit more by kind of the reality.
No upside from the reality of what you've seen in the field.
So so weve had gone through at several iterations on the type curve on the CBP and one integration on the northwest shelf and the type curves that you're seeing in the corporate presentation. You know as Danny previously discussed that the REIT conversions and are very accrete as they make us a lot of money.
You know, we spend a little bit but in the long run it's it's much better for us. So both cases contemplate a REIT conversion at 365 days from at peak production rates and we kind of got that number bielecki historically across both basins and projecting where we're getting to that so.
Pete spot of fluid level, our fluid movement that we can convert from that larger volume E.S.P.T. the smaller volume rod.
Okay, Great and just my last one.
I was lifting to another smaller companies with.
Single bake basically focused that also has done.
Good hedged coverage and we haven't Terremark last week that they have been getting more inbound calls.
Some folks looking offer financing.
Into various terms then they can ever recall happening in this current environment. So I was just curious what what you're hearing is.
As far as.
Folks who Uh huh.
Like to find a way to get your money.
That's a good question or that's yeah that is definitely a good question Nolan and comparing to the other company I would say that I'm, absolutely. We have probably seen more density and inquiries and over a two month period than we any other two month period prior to that not only not only for the inquiry is a real.
It's two possible financing is available and you know and different sorts not just your traditional conventional banking, but outside of that in addition to that there's been a number of inquiries as it relates to folks that are interested in doing something along the lines of participating somehow or some way with the company whether that's to Joe.
Joining in of as they as like that's a side by side idea or whether it's to join in as a joint venture. There's a lot of variety of ideas that have been kicking around more so than what we've ever seen before.
Great. Thanks, a lot.
Thank you know.
Thank you as a reminder to ask a question in your press Star One. The next question is from the line if done Mackintosh Johnson Rice.
Good morning.
Oh.
This year's budget Youre out pretty early drop in audience.
Good for one.
Capex budget down to 32 million.
Last night sounds like shaved another 5 million or so offer that what's what's the driver there.
<unk>, obviously, you're still focused on the pump conversions.
But.
Maybe a few of those and you're thinking about or more favorable service terms on any color there would be appreciated.
Danny.
Yeah, no done what we've done as we've gone back and studied and what we what we can see historically as our failure rate.
And we've cut back just to the bare minimum so we're not proactively doing the rod conversions like we were last year and even in Q1, where once a well did reach the point, where it made sense to put it on raw conversion. We went ahead and did the job what we're looking at now as you know with the with the lower production rates.
We think that the failure rates could be even a little bit lower we're hoping and but even if they're not these are kind of it's just kind of a bear main bare bones maintenance or not he made maintenances into proper word it's as as a well that goes off in is a candidate for or Rod conversions will go ahead.
Do it, but we're not going to proactively.
Go out and do those jobs and so I think that's what you're seeing is when we first contemplated that 30 to 32 million, we were going to continue but doing nine to 10 rod conversions a quarter and now we're just going to do them on an as needed basis based on our projections and that's the difference and I think danny's team has done an excellent job negotiating.
Lower service costs down environment, and so I think part of that that change and budget is seeing the new environment, we're working in.
Alright, great. Thanks, and then sorry, if I Miss this but you know recognizing that the borrowing base redetermination is still ongoing.
I wish him there between the timing of data and the closing of the doors.
The other assets in the portfolio you all can think about potentially monetizing not so much.
Serves as more along the line I'm thinking more along the lines of midstream.
Yes, that's particularly up on the shelf, where you've got a pretty robust portfolio. There. Thanks, yeah, well that's a that's a mouthful, but those are all very good questions.
There's no there's no doubt that as as was mentioned earlier with the Randy's comments. His remarks that we are in the middle of Redetermination now, we anticipate probably another two or three weeks before we're gonna be actually having they sit down or the equivalent of a sit down with the with the banking group, but that's also mentioned all that material all the information that we typically.
Provide for them. During these cycles has been sent over and so we're looking forward to two crossing that bridge and seeing what results. We have there there's no doubt that the Delaware of sale will will contribute.
To to the.
The payment of $37 million, just less than 10% of down on the revolver is going to go long ways. It will be it will be I wouldn't call impactful, but it will be important. So we are we're counting on that and.
And so in addition to that I think that as it relates to are going forward and what we can put forth in terms of being a compliance we feel pretty comfortable with.
Alright, great. Thanks, very much you bet.
Our next question is from the line of John White with Roth capital to see if your question.
Yes.
[noise] Mr. Rob.
Yes.
Okay.
Mr. What your line is open for questions.
Hi.
Yes.
Really.
Hey provided.
Procedures.
And also Mr powers comment.
I mean shut in policies.
Ah if it was stated I missed it but what was production during April.
John We haven't we have not filed April production, yet so that's not not publicly available but we.
We did curtail near the end doesn't mind, but the rest of the monthly are on track, where we were in in marriage.
You mentioned shutting in about 100%.
Starting April 23rd so.
That's a good yeah.
Yeah, the jump that that you kind of look like.
I guess the best estimate would be maybe if you looked at March and you probably.
Yeah, probably maybe knock of three or four or five days off that number on average that may get you close I don't know I haven't done that calculation, but that would be my guess.
Okay really appreciate it thank you.
Thank you John.
Thank you there are no additional questions at this time I'll hand, the floor back to management for closing remarks, okay. Thank you operator, well listen once again, we appreciate everyone Oh, the ongoing support is appreciated as well and we know you're busy so we're going to we're going to sign off and if you do have follow up questions, which may you may or may not have feel free.
To reach out and put those calls through we'll we'll we'll make sure that there are people that are available to respond to him and once again. Thank you for your time.
This concludes today's call may disconnect. Your lines at this time, we thank you for your participation.