Q4 2020 Earthstone Energy Inc Earnings Call
[music].
Good morning, and welcome to Earth Zone Energy's conference call at the time, all participants are in a listen only mode. A brief question and answer session will follow the formal presentation.
If anyone should require operator assistance during the conference call. Please press star zero on your telephone keypad and as a reminder of this conference call is being recorded joining us today from Earth Zone are Robert Anderson, President and Chief Executive Officer, Mark Lumpkin, Executive Vice President and Chief Financial Officer, Steve Collins Executive Vice President of operations.
And Scott the Landers, Vice President of finance Mr of the lender you may begin.
Thank you and welcome to our fourth quarter and 2020 year end conference call before we get started I would like to remind you that today's call will contain forward looking statements within the meaning of section 27, a of the Securities Act of 1933 as amended and section 21 E of the Securities Exchange Act of 19 <unk>.
Before as amended all.
The management believes these statements are based on reasonable expectations. They can give no assurance that they will prove to be correct. These statements are subject to certain risks uncertainties and assumptions as described in the earnings announcement, we released yesterday.
And in our annual report on form 10-K for 2020 filed yesterday.
These documents can be found in the investors section of our website www dot or stone energy dotcom.
Should one or more of these risks materialize or should underlying assumptions prove incorrect actual results may vary materially.
This conference call also includes references to certain non-GAAP financial measures reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday.
Also please note information recorded on this call speaks only as of today March 11th 2021 the.
Thus any time sensitive information may no longer be accurate at the time of any replay or transcript reading.
A replay of today's call will be available via webcast by going to the investors section of <unk> website and also by telephone replay.
You can find information about how to access those on our earnings announcement released yesterday.
Today's call will begin with general comments from Robert Anderson, Our CEO, followed by an operations update from Steve Collins, Our executive Vice President of operations.
Our CFO Mark Lumpkin will provide comments regarding financial matters and performance and then we'll have some closing comments from Robert prior to opening up for Q&A.
Now ill turn the call over to Robert.
Thank you Scott and good morning, everyone. We appreciate you joining us for our fourth quarter and year end 2020 conference call.
The 20, certainly presented many unexpected challenges, but our solid result results are evidence of the strength and resiliency of Burrstone, we achieved a 14% increase in production in 2020. Despite of 68 per cent reduction in capital expenditures from the prior year with average daily volume exceeding our production.
Guidance by about 6%, although oil prices declined dramatically in 2020, our strong commodity hedge position helped us keep adjusted EBITDAX essentially flat with 2019 and generated over $72 million in free cash flow, providing us the ability to reducing our outstanding debt by nearly one.
Third.
We delivered on our 2020 goal of reducing our leverage ratio to below one times adjusted EBITDAX coming in at about <unk> eight times for 2020, Mark will provide some additional results for the year in a moment.
Our strong financial position supported our ability to execute on our growth strategy of increasing scale with high quality accretive acquisitions.
I'll spend a few moments talking about the acquisition. We did this acquisition of independents resource management, or Iran, which was announced in December and closed on January seven 2021 added complementary Midland basin assets. It increased our production and adjusted EBITDAX by approximately 50%, while having a minimal in.
Impact on leverage the $182 million acquisition of I R. M was underwritten by a strong P. D P value of approximately $173 million.
And enhances our drilling inventory by about 70 operated drilling locations from IRI EMS core acreage in Midland and Ector counties to our existing drilling inventory.
We expect the I R. M acquisition to result in significantly increased production in 2021, with very minimal incremental general and administrative costs, allowing us to continue to achieve high margins in our operations with the benefit of added scale.
A large majority of I R. M production comes from its core acreage in the Spanish Pearl project area in Midland and Ector counties.
The approximately 4900 net acres there are located in well delineated areas with the existing producing wells on all sides from various operators and further derisked by <unk> own development on the acreage, which is about 93 per cent operated and 100% held by production.
The Spanish Pearl locations compete for capital.
With our Midland and Upton County inventory, where we estimate.
Irr's ranging from 70% to 90% on of 10000 foot lateral based on $50 oil and $2 50 gas flat for life.
Integration of the assets.
It has gone well and as a complement to both our folks at our stone and the I R. M. Team. We are pleased with how smoothly. The integration has gone and are fortunate to have been able to retain the large majority of Iran's field personnel and for those of you in the field from Iron am listening today welcome aboard.
We should start to see the results of deploying our operating approach to the I R. M assets by mid year, which we expect will result in some improvements on the operating efficiency and cost sides. We're also looking forward to including I R. M assets in our 2021 drilling program and seeing those results in the near term.
In terms of our 2021 capital plan that we have previously outlined the one rig program will be funded well within our expected operating cash flow.
The resulting in significant free cash flow.
We will continue to pay down debt, while considering options for a second rig.
Beyond our drilling and completion plans, we continue to be focused on adding additional scale through acquisitions, while maintaining our financial discipline.
Now I'm going to turn the call over to Steve Collins to provide an update on operations. Some of you on the call today know Steve in that he manages all of our operations Steve has been with US at our stone and predecessor companies and has worked with Frank and me for over 25 years, not the date, either Steve or myself, but actually we work together as a field engineer.
Errors in the early 1990, so with a long history working together I'm happy to have him join us today, So Steve about it.
Thanks, Robert I'm glad to be on the call.
In the fourth quarter, we began completing wells, we had drilled but not yet completed when we paused our 2020 drilling program last spring.
In December we completed the six wells on our Ratliff project in Upton County.
And which we hold 100% working interest I.
I won't rehash the production results since we released that with our operations update in January but we're very pleased with the performance of these wells.
We exited 2020 with five wells still awaiting completion, which are all of our Hamman 30 unit also located in Upton County, we.
We have finished completion activities and expect to turn these five growth three seven net wells to sales in the next week or so.
We've also resumed our drilling program with the rig we're gaining drilling operations in the past week on the three well pad in our Hamman Midland County project.
We are where we plan to drill one well in each of the Jo mill lower Sprayberry Wolfcamp B upper reservoirs.
We will then move the rigs the acreage that we recently acquired from my room.
Drilling a four well pad in the Spanish Pearl project also in Midland County.
Our full year of 2021 capital expenditure plan anticipates, the we will drill 16 gross 14.8 net operated wells and.
The spud an additional five gross or three seven net operated wells.
Alluding the five gross wells in Upton County that will be turned to sales next week, we anticipate turning to sales. The total of 16 gross or $13 five net operated wells in 2021.
Throughout 2020, we continue to focus on cost management and driving down operating costs.
With 2020 lease operating expenses of averaging just $5.21 per Boe.
For the year.
With the addition of the R M assets.
We anticipate a modest increase in L O.
In 2021, but we will remain acutely focused on cost management throughout the year.
We will incorporate some of our operating philosophies and artificial lift changes like moving from electrical electric submersible pumps to gas lift which should reduce operating costs in the long term.
The enhanced scale of our operating business should also help drive some cost savings over time as we consolidate service providers.
Now, let me address the impact of the extreme weather winter weather, we had in February.
There's other operators experience everybody experienced the harsh weather and loss of power of caused significant disruptions in our operations.
I'm happy to say that the large majority of our oil production was back online in four of five days.
The operations are now back to normal with no permanent impacts.
Once we gather all the sales numbers, we expect of February will be down about 25 per cent from our plant from our plants.
I'll now turn the call over to Mark to review the financials Mark Yeah. Thank you Steve.
Good morning, I'm going to start with the recap of our balance sheet and liquidity.
We generated $8 $4 million of free cash flow in the fourth quarter, which brought us to $72 2 million of free cash flow for the year.
As you all know we've been focused on paying down debt with our free cash flow was another $15 million of debt reduction in the fourth quarter for the year, we reduced debt by 32% from $170 million day $150 million at year end and our debt to adjusted EBITDAX ratio was similarly improved decreasing from one two times at year end 2019.
Two 0.8 times in 2020.
As Robert mentioned, we did close the IBM transaction in early January so when adjusted to include the debt related to the irony of acquisition. We had an estimated $245 million of net debt outstanding at year end, what the borrowing base of 360 million in total liquidity the liquidity of approximately $115 million.
With combined or stone plus I R. M. Twenty-twenty EBITDAX of 20 $223 million leverage as measured by total debt to adjusted EBITDAX at year end would've been one two times as of March 1st we had reduced our net debt by approximately 27 million compared to the 245.
Dollars of beer in net debt adjusted per IRI M, which also increased our liquidity by $27 million.
While we won't necessarily pay down more of net debt in the first quarter as the impacts of operational downtime in February impacts cash flow. We do anticipate continued pay down of debt throughout the year.
Our accrued capital expenditures totaled about $23 billion in the fourth quarter and $66 $8 million per the year, which was slightly below the midpoint of our 2020 guidance. This represents a 68 per cent reduction in capital expenditures on a year over year basis, as we drastically cut capital expenditures amidst the oil price.
Collapsed last spring as you all know as detailed in our previously released guidance, we expect to spend $90 million to $100 million in total capital expenditures. This year utilizing the one rig that we recently deployed based on the spending plan. We believe we will generate significant free cash flow and in turn for the primary use of that significant free cash flow to be.
Net repayment.
Now looking at our income statement of let's start with the top line total revenues in the fourth quarter of 2020 were $36 $7 million.
Our average price in the fourth quarter. It was $26 at 92 cents per barrel of oil equivalent by commodity our average realized price per crude oil in the fourth quarter was $41.43 per barrel natural gas averaged $1 65 per Mcf and Ngls averaged $17 18 per barrel for the year.
Our average price per BOE was $25 to 85 cents Fortunately with our hedging strategy. We also realized just over $17 per barrel of oil produced in 2020 and that amounts to just over $10 per barrel of oil equivalent when including the all components of our production.
Per our production standpoint, our fourth quarter sales volume averaged 14809 barrels of oil equivalent per day, which was comprised of 48 per cent of oil 20 per cent natural gas and the remaining 24 per cent from Ngls as Steve mentioned, we did bring on six new wells near year end and they did not contribute meaningful to the fourth quarter for the full year of 2000.
20 average daily sales volumes increased 14% compared to 2019 up to 15276 Boe per day, which exceeded our production guidance by 6%.
On the expense side on a per unit basis are all in the fourth quarter cash cost, which includes lease operating expense production and severance tax cash G&A and interest expense came in at $12 20 per barrel of oil well what it of $11 eight for the full year.
Our lease operating expense came in at $5.26 per B O E in the fourth quarter and for the full year average $5 from 21 cents per BOE, which was well below our guidance range of $5 25 to $5 50 per Boe.
On the general administrative side, our adjusted per unit cash <unk> expense was $4.57 per Boe in the fourth quarter, bringing cash G&A expenses for the year to $3 25 per Boe.
The lumpiness in our fourth quarter cash G&A is largely the result of awarding cash incentive compensation in the fourth quarter due to successfully achieving our 2020 operating results compare to a typical of gear in which we would accrue awards more evenly throughout the year.
That's the side on the G&A with continued reductions in our cash G&A the $18 $2 million in 2020 is the lowest we've reported since 2016, one way or a much smaller company with no Midland base of operations and produce less than 5000 Boe per day, so less of a third of our current production.
The continuing reduction in cash G&A and growth in production have allowed us to continually improve our cost structure, reducing cash G&A per Boe E V. O E by 54 per cent from over $7 in 2017, two of the $3.25 per BOE in 2020, what the acquisition of ire EM and our continued focus on managing cost.
And very little incremental G&A related to the independents or ire of acquisition, we do expect to continue to lower our per unit cash G&A cost in 2021 to an implied $2 77 per Boe at the midpoint of our guidance and like we do in all aspects of our business. We continue to focus on improving our cost structure and our margins.
So while we've made good progress we're not done yet.
From an income standpoint, we reported a GAAP net loss in the fourth quarter of $18 $4 million or a loss of 28 cents per year, which included an unrealized loss of $21 6 million in Arizona. The road of contracts are adjusted net income.
What's the profit of $5 $5 million or eight cents per diluted share in the fourth quarter for the full year 2020, we reported a GAAP loss of $29 $4 million or a loss of two cents per share and adjusted net income for the full year was a profit of 20 of the point $7 million or a profit of 46 cents per diluted share we reported adjusted EBITDAX of two.
The $9.8 million in the fourth quarter, bringing full year 2020, EBITDAX to $144 $3 million, which was down only 1% from 2019, despite oil prices dropping by 31 per cent and our capex being reduced by more than two thirds.
As of the practice, we remain well hedged for 2021 with swaps of approximately 85 per cent of the mid point of our oil guidance.
Approximately 71 per cent of the midpoint of our guidance for gas at average prices for oil of a little bit over $48 of WTO I basis, plus a little bit of a positive differential and $2 of Eddie one cents per gas. We have also been chipping away at our 2022 of hedge program and expect to do so over the course of this year going back to our production levels and the impacts of the winter weather.
Other as Steve mentioned, our production was clearly impacted and we estimate the impact to be roughly 25% of volumes of volumes in February which will obviously impact our first quarter results from a full year standpoint, we think this is roughly a two and a half per cent impact on production for the year or about 500 barrels of oil equivalent per the year.
Given that our production guidance includes the plus or minus 750 Boe range from the midpoint, we're not adjusted our production guidance at this time, but this impact will clearly bias.
More towards the lower end of the production range with that I'll turn it back to Robert Thanks, Mark a lot of information we provided both yesterday in our press release in our K and today this morning.
As you can tell 2021 has gotten off to a strong start for us we're super excited about the additional scale and the drilling opportunities as a result of the IRS acquisition, but as you can tell we're just getting started and we have a great platform for continued growth or stone is well positioned with the good inventory of high Mark.
<unk> low cost drilling and while we are pleased to see a more attractive commodity price environment emerge. We remain focused on a one rig program for now but continue to consider whether adding a second rig to the now larger combined asset base will make sense later this year.
We're very optimistic about 2021 in the future. We believe our operating plan, which is directed towards areas with the highest drilling returns will generate significant free cash flow during the year, we remain focused on maintaining a strong balance sheet and reducing debt with this free cash flow. However, with the I R en masse, it's fully integrated.
We continue to seek additional acquisition opportunities that create further scale and complement our low cost high margin operations. Our focus remains committed on creating shareholder value in everything we do and we will continue to look at consolidation opportunities opportunities through that lens now with all of that operator.
We'll be glad to take some questions.
Thank you at this time, we will be conducting the question and answer session. If he would like to ask the question. Please press star one on your telephone keypad. The confirmation tone will indicate that your line is in the question queue. You May press star two if he would like to remove your question from the queue for participants.
It may be necessary to pick up your handset before pressing the star of keys.
Our first question is coming from Neal Dingmann with true of Securities. Please proceed with your question.
Morning, all thanks for all the details Robert My question is first just on some of you just mentioned you smartly mentioned about the potential obviously with prices today and your pristine balance sheet about potentially adding the second rig I'm just wondering how do you and Steve and Mark the guys thinking about the optimal you know when you. When you were looking at this and thinking about the optimal.
Or is it just purely.
With prices in and what level would give you the best free cash flow is it you know of combination of of what you know the one or two rigs whats going to give you. The best combination of sort of production of our production and free cash flow growth. Just wondering when you. When you when you think about optimal level, what what do you all sort of thinking about.
Yeah Neil of it it does depend on your scale of course and with this added acquisition that helps and I think it has to we're driven by cash flow so trying to maintain the balance between.
Growing within cash flow and how how much growth, we actually get out of that and the timing of all of that so.
We're looking at it every day and there's some of US who are anxious to put a second rig to work and there are some of US who are anxious to walk before we run and will at the appropriate time considered that second rig again, but I think it's a balance between.
Cash flow and the amount of capital.
He would spend.
Okay and then how do you think about time of you you've got a you know when you're in the.
In the press release it was good to see you know you've already been pretty active on drilling and you talked about even the four upcoming are of Iran. In the Spanish Pearl of the London up to and how do you think about you know that in regards to completion of or you know the other way I guess, we look at it as analysts the sort of 'twenty one production timing based on those completions, how should we think about.
Those.
Yeah as we've done in the past, we generally complete wells kind of in packages.
So we will get the first pad drilled will be on the second pad and then will the.
The plan is to start initiating completion. So you know I'd say by Summertime, we're starting to put some wells online and then the back half of the year will be you know the Upton County wells. So it's you know it's going to be a it doesn't make sense to go out there and just complete that three well pad by itself unless we've got that other four well pad ready.
The go so the Greek and just move right over but.
Part of that is a function of all of the service companies and their how busy they get over the next few months.
Yeah.
What would you do on the on the 10 of 11 would you do simultaneously.
We have not explore all of it we have not done that we've seen other people do that you know there's probably some timing efficiency that helps you. But then there's also the logistics of doing that the first time, so and it also depends on how your pads or set up a you know whether you've got big pads are.
Typical pad size. This year is going to be around for and maybe we'll get one that's five or something like that so then it might make sense in a bigger pads to have two frac crews out there, but we have not done that yet and not the wear resistant we just haven't had the right opportunity.
Absolutely and then if I can sneak one last one the and I just can't help but notice on slide 16 for the Eagle Ford you you'll show the zero.
The drilling locations. There you know there seemed to be a big market out there right now for production and cash flow you know as I mentioned earlier sort of a pristine balance sheet don't need of sell anything but is this consideration in the Eagle Ford.
It's always been of consideration even going back to when we bought our first operated asset in the Midland Basin, you know back in 2017. It just won't command any capital of the allocation of capital is much more suited to go to the Midland Basin based on returns.
And we'll continue to keep that asset because it gives us a good footprint. If we find other opportunities in the Eagle Ford, which there are several things that could make sense for us to.
You pursue.
Absolutely. Thank you.
Thanks Neil.
Thank you. Our next question comes from Scott Hanold with RBC capital markets. Please proceed with your question.
Yeah. Thanks. Good morning, you all obviously of the history of of looking at accretive deals and it's certainly been a pronounced part of of your your discussion here in your prepared comments can you just give us a sense of like you know given what we've seen in the moving oil prices and even some of these ex.
The valuations like how do you look at it right now is there when you look at some of these private opportunities out. There is is there more of less interest today and how do you all think about using your you know you're your stock is is the currency.
Yeah. Good question Scott. So we think that there is a a pipeline of opportunities out there in various basins that we're focused on both.
Both public and private I think youre going to see some of the public guys start to sell off non core assets, which we will review and maybe participate in processes, but we'll continue to talk.
Talk with private guys, who recognize the scales important.
The cash they take today.
It is good but maybe they want to write some of the upside and so we'll use equity and cash.
Cash and we're going to continue to focus on you know each deal separately in terms of the structure of how we do that whether we want to make sure we don't get over Levered and each deal looks a little different in the cash flow profile, probably has some impact on you know what kind of leverage we ended up with the deal. So.
I think I don't think that our playbook changes much as prices improve and because I think there's still an opportunity to continue to consolidate.
Yeah, yeah, but it gets it to the 0.2 of them have you seen sellers you know change that you know the appetite to sell by by the privates and and others do do you see any change in that given what's happened or less you know a couple of months.
I think they've maybe accelerated their mindset of selling.
Because you know you never know how long.
The cycle of improved prices is going to last Oh, sometimes that's the dictated by some foreign countries and so we'll decide you know I see I see some improved activity level of divestitures happening in the market as we speak there there are more guys out there.
And all of the banks are busy advising folks on on sales.
And you did mentioned the you know the the basins you'd look at can you help us to find that I mean, obviously, you're focused primarily in the Permian here and you've obviously talked a little bit to the Eagle Ford, but like when you look at your play you know you're playing field.
How are you thinking about that or are you should we expect you guys, primarily focusing on the Permian or is there other other opportunities outside the Permian the look pretty attractive as well.
It is the primary focus is the Permian and then secondarily is the Eagle Ford and beyond that.
They were not focused on looking at anything else.
Okay. Okay, Okay. The I just misunderstood that.
[laughter] I just wanted we weren't going to go to the Appalachian They weren't going to go to the Appalachians and Frank Pete there.
And any surprises with the idea of them you've heard of for two months of any surprises so far that you're seeing good or bad.
We integrated it very quickly and that goes to the talented folks who did a lot of hard work trying to do that and I don't think that we've seen any surprises to the negative. The positive is the response and I'm speaking for Steve, but the positives I hear from Steve or the response from the folks in the field.
And you know being part of the bigger organization and we're going to spend some capital and I think theyre, all really glad to be onboard Steve.
The thing else, you've seen positive or negative.
No, it's mostly positive the people have reacted well they.
Or encouraged by a new philosophy and willingness to.
Put some capital to work and make the changes that we need of Mac.
I appreciate it guys. Thank you.
Like Scott.
Thank you. Our next question is coming from the line of Dun Mcintosh with Johnson Rice <unk> Company. Please proceed with your question.
One of Robert.
Hey, Dan.
Maybe for your Mark.
So you know you can't have it both ways of the hedge book of the huge benefit of last year now that it's the negative this year, but you know you are pretty well hedged or under 50 Bucks I was just wondering how you kind of think about hedging going forward with you know with the strip here.
At 60 for this year of Little Boy for next year at what point would you look to start layering that on it and would you maybe we are a little more room for upside with prices higher.
Let me address just one thing and of and you said it but just for everybody's reference you know we.
We manage for the downside risk of little bit and Luckily that played out very well last year and yes, we have given given away, perhaps some upside this year, but you can't have it both ways right and so it's a balance and more debt more hedges.
The more activity you know you underpin of drilling program at a you know whatever price deck, you've hedged as another way to look at it so.
The difficult when prices move around and investors or analysts you know things of that you've left too much on the table I'm comfortable where we are this year.
Well, we'll continue to think about 2021 as we layer in a few more hedges mark Yeah. He means 2022 day, sorry, Yeah. I mean, we've got this philosophy of that post OPEC at the end of 2014. It was a complete paradigm shift and we've traded generally in the range of 40 to 70 or thought of.
As Ben Yeah, let's make sure we're really well hedged for one year and moderately hedge the next year and in some cases, we've hedged further out there I mean some of the hedges we had in 2020 that we benefited from work done in 2018, and you know what.
And in particular, I remember is $73.06, we hedge that out longer because of the strip was.
And of Contango and it was really strong yeah here again of the.
Strip continues to strengthen and particularly the.
Swaps in the contango, we may hedge out further I mean, we're sort of done hedging in 2022 for right now, but there's no doubt we will continue to chip away at that through the course of the year I'm, probably not for a couple of months again, but we look at it I mean literally every day and think about it and yes, we are a little bit more bias to downside protection.
Then probably some of our peers are.
And that's just our strategy and discipline and we just try to stay consistent with it and like what it does you know throughout the cycle the bigger picture.
No I appreciate the current that's good to hear and then.
Quick follow up.
I appreciate the color on the impacts relative to production with the winter storms, but anything else that we should be aware of either getting that rig up and running do those completions come on I mean, I know, they're all of them, but you know that.
Everything come on on time, just that and then maybe any any expectations around maybe the additional capex or opex with energy.
Because of any damages that might've occurred.
Yeah, I mean everything's.
We're relatively early in the year, even though are you now have almost 90 days into it but everything is on schedule and so far so good from a scheduling standpoint, no major impact from us.
Extraneous cost standpoint related to the way the winter storms, maybe of well or two needs you know of workover, but they probably needed it prior to that anyway. The the only thing I can say on additional capex is with the improvement in prices could we see.
Some non op activity and obviously, that's you know we're not aware of anything other than what we've already got in our capital plans, but could we have a partner who decides they want to pick up another rig or you know increase their.
Their activity level and would we get some additional <unk> this year.
So far I don't think that's going to happen, even with the improved prices because of their plans were probably pretty well set. So our focus isn't that you know we're going to see a bunch of capex increases from our non ops, but it could.
Alright, thank you.
Thanks, Don.
Thank you. The next question comes from Noel Parks with Tuohy Brothers. Please proceed with your question.
Good morning.
No.
I just had a couple of things you know when you're talking about are the targets are going to be drilling you mentioned, the the Jo mill and I hadn't really paid a lot of attention to.
How results been trending in net formations.
You drill it on your.
Your existing.
Acreage here before the acquisition did you drill it.
And is is it pretty well established that's part of what you expect from results there or is there still some work to be done.
Yeah, no. It's it's a well established reservoir target for lots of companies are the the the Jo mill, where drilling is on our existing assets.
In Midland County, and there's lots of data in Midland County County to show you how good the Jo mill is and it is a good target we participated in some non op Jo mill wells last year and in a stack of Jo mill, plus lower Sprayberry and Wolfcamp a I believe our guys are telling me that.
The Jo Mills, probably the best of that group of wells that we participated in so not a not a new target and not something exploratory you know us nowhere.
The most risk we're going to take a sort of of developed cash at this point of MEO and that's that the step out of the maybe go into of Wolfcamp C. Like we did in and our Upton County block, where Apache had drilled a couple of C wells in and had really good results and we had similar geologic characteristics and so we drilled the wolfcamp.
C Wells also had good good outcome.
Great and then I was thinking about the but I wanted to get your thoughts on maybe.
Where you might be headed as far as Frac intensity goes.
And you know we're in a.
Pretty different much better spot oil price environment now than they were just the beginning of the year.
The possibility of the services might be getting a little a little tighter and of course, when things where we're price.
We're really weak I think there was a lot of interest of and maybe the scaling back our fracs just to see if if you you actually where we're benefiting from the you know the incremental spend to do you know.
Bigger bigger ones, so just or are you.
Are you inclined to have bigger at this.
Or or do you still think there is anything to be learned from.
What you can achieve by the way scaling back of it.
Steve's the expert here on our team of about that my only comment is that it's not necessarily price the dictates that.
As much as kind of where you are in the development. So do you have offset wells and things like that but I'll, let Steve address the intensity side of it we've been pretty consistent.
Yeah, we've been really consistent and we've not changed Frac design based on price.
We try to make the best well we can.
Every well.
Like Robert said, whether it's usually we usually look at whats open around that Wellbore parent child relationships things like that.
And we just try to make the best well every time, we tweak our designs a little bit every time and we seem to see our type curves moving in the right direction.
And.
So I don't think we're going to change considerably.
Great. That's all for me thanks.
Thanks, Phil.
Thank you. The next question comes from John White with Roth Capital. Please proceed with your question.
Good morning, gentlemen, and congratulations on a very nice year in the you know.
The troubling environment.
Just curiosity on the February production in the Winter Storm was there one particular.
Reason or one particular problem or well freeze the midstream gathering.
Was there one one items it was predominantly the result of the storm.
Steve its electricity right electricity was the biggest but it was everything of the oil trucks couldn't run the roads.
If a well you couldn't put your saltwater disposal to the third party disposal because they didn't have electricity so they couldn't pumping away.
Even our own people had trouble getting around so it was a combination.
Of everything and then when you did get it going around in the midstream didn't have their compressors running so he had no place to go with the gas. So the whole basin is a giant bal.
Balancing act and it just totally got derailed. So it's it's back up and balance of running now, but it did take a week or 10 day.
Okay. That's good color I appreciate that and on the possibility of adding the second rig.
Is there what's the principal factor there is at the C. W. A T I go above 70 or <unk>.
If you get the some non.
Non op increased activity would that preclude you from adding a second rig I know you said you don't anticipate a lot of non op capex the.
Just give us a little more of your thinking on adding the second rig.
Yeah, It's it's not price I think we're in a pretty good price environment at least in the near term.
And it's we've got plenty of free cash flow. This year, even if we do get some additional non op activity I'd say, it's a you know making sure we can.
Operate this rig in and the the whole logistics of the first one going smoothly and then bringing in the second one you know we're not staffed.
To run multiple rigs like five or six and so you know, we're pretty small still and let's get this one running pretty efficient and then we'll bring in the second one you know later in the year is kind of what.
We're looking at and considering its also a function of you know what kind of services are going to be available yeah, a little further down the road.
Okay.
Thanks for the additional color there. Thank you.
Thanks, John.
Thank you. Our next question comes from Gail Nicholson with Stephens. Please proceed with your question.
Good morning.
Remind me what percent of your low.
The first is variable and when you look at the work over activity in 'twenty, one how does that compare to 'twenty and then are you doing any initiatives this year to potentially improve on a go forward basis.
Wow, that's a lot of questions there of Gail that will unpack Ah Ah I I don't know the exact breakout between variable and fixed and maybe Steve does we do break it out in our reserves and the way we calculate things.
I wouldn't guess that it's 50 50, but maybe somewhere around there.
I don't know that exact number of already maybe a little less than 56, yeah. It's variable.
And then the Workover side of it you know we've got some additional work over plan because of Iran and their wells.
And just the way, they're operating conditions right, Steve I mean, we're that's correct and we see some upside in the items wells and we'd like to put some capital towards that and with the increased prices.
Some of those Workovers are workover budget may grow a little bit this year.
Because of all of those wells each of them attention we.
Can change lift methods and hopefully reduce failures, which so that'll take a while to show up but in the long run. That's that's where you make all of your progress in gas maybe I'll just add a part of a little bit of of historical financial.
Perspective.
You know we've typically.
Well I shouldn't say typical because it's moved around.
A couple of years ago in 2019, our Workover component went up pretty significantly and there were some specific reasons for that are and there were sort of just the.
A wave of activity of that needed to be done.
That happened I mean sort of year over year basis in 2020, our workover went down by.
By about two thirds of which part of that was there really was a pretty big wave in 2019.
What we.
Record of sort of internally on the Workover piece for 2020 was actually pretty similar to what we did in 2018, so there's a bit of it in.
In 2018, so there's a bit of a spike in 2019 with ire M.
There is unquestionably a lot more workover, we're going to do on that basis, our own assets, probably not that dissimilar versus last year, but we've identified quite a bit more work over work that either needs to be done or we want to do as we do some things different from a loss of mechanism standpoint.
The other things. So this year, we definitely have more workover built into our guidance and our expectations than last year and our hope is well one maybe that doesn't coming quite as high as as we think it will it could be higher but we think it's a reasonable number that we've got embedded in our guidance.
And in our forecast.
Two of our hope is we have a little more of an elevated workover.
This year and then it sort of back to kind of combine normalize or stone plus independents levels next year.
And Gail I might add and Steve mentioned this and so did mark but you know the way we look at this.
You spent some money today you that lasts a really long time, because you have changed the operating philosophy or what have you and you run time stays up so it benefits on the low side, but also on the production side and we try and fix things you know just one time.
And last of really long time and get some really good run times out of the things we're doing.
Alright.
That in 2022, workovers likely be laughing in 'twenty, one and there's a good chance of L. B.
As part of their improvement on a go forward basis and the six of the success this year yeah.
Yeah, I mean, I think that's fair I mean, if you look at last year and of course. The this is archstone stand alone because of the acquisition didn't close until early January we averaged $5 21 per Boe for the for the full year of total of all the way which includes the workovers.
Yeah that might have been just a little bit low just because of the environment and some things we did.
Tried to not spend as much money in 2020, and the volume or in but you compare to the 521 that we had on Earth since day one.
On a standalone basis last year or two you know the midpoint of our guide for this year of 625 for the book higher I mean, you sort of with the scratch. Your head of of why is that well I mean really the driving factor is independence of ours is probably maybe a little biased up from the 521, but it's not like seven bucks, but the bear.
Pieces, just the the the chunk of additional expenses we expect.
Some of them just kind of the general OE side, but largely.
A step up in Workover expense.
Great. Thank you and then.
The over 60 per cent of your oil production of on pipeline in 'twenty, one I think that's up versus 42% in 'twenty. When you get to a 100 per cent and does the move onto pipe and free of your realized pricing on the oil side.
Yes, it does improve our pricing.
Trucking is a little bit more expensive.
<unk>, although in 2018, I think we saw trucking rates at zero at different times, just because of the competition for barrels.
It's it's a probably for us in practical to be 100% on pipe just because we don't have big consolidated blocks of acreage. If you did then you could probably get there, but when you got an outlier asset that you now has 10 wells and is a long way from our pipeline.
Sure, that's probably always going to be trucked so at.
At this point, we don't have our target out there, but we wouldn't want to get to but we've got a couple of other areas that we are planning to put on pipe and it's just a matter of the timing between us and the and the gatherer to get all of that done it probably won't happen this year, but probably next year.
And then on the realized pricing improvement. So we think that's like maybe 510 cents.
The average basis company wide or any thoughts on that.
It's probably higher than that more like maybe 50 cents.
Pipeline barrels you now are less than a dollar for the most part and truck barrels you know sometime of run about 50 or more.
Great. Thank you.
You bet.
Thank you as a reminder, if you would like to ask a question at this time. Please press star one on your telephone keypad.
Our next question is a follow up coming from the line of Dun Mcintosh with Johnson Rice income.
These proceed with your question.
Hey, Robert Sorry, I think we've talked about of the world, but you know with the impacts but the.
Just sneak one of if we could just get a little bit of color on kind of the traject trajectory of that production profile. This year kind of when you think about it.
The full year guide and how you kind of get to the midpoint.
Yeah. Thanks, that's a good question of Smart here, let me try to address that one. So you know of pre February I think we're a little more of kind of Q1 was probably the highest quarter for per reduction standpoint, and it still might be but our sort of forecast was we brought these five wells online excuse me six wells on line at the end of the.
Last year and it was pretty flush production for the first quarter and it still is minus the the downtime in February.
The.
What's the February impacted the sort of shifted the shape just a little bit where you know Q1 is going to be.
You know, 8% lower than we thought it was going to be just based on February being 25% lower or something in that general ballpark. So that's come down a little bit versus what we thought.
Three or four weeks ago that ends up making like our profile, it's pretty flat throughout the year I'm, that's probably still hitting something what the 20 handle on it in the first quarter, but probably not a ton of higher than that you know with the midpoint of our guidance being $20 to 5000 barrels a day.
That really kind of looks like pretty flat production throughout the year, a little bit of a decline in Q2.
And probably so in Q3, and maybe a little bit of pick up the Q4, but it's pretty flat I mean I'll say this.
You know, we obviously kind of.
And fairness reduced the midpoint of our guidance based on the impact because it was probably five to 600 of BOE per day for the year typically we like to be a little conservative on the guidance and the midpoint.
Free the February storm was a little bit lower than the midpoint of our forecast now our forecast is lower it's still within the range of of the guidance, we gave but it's definitely on the lower end.
So you really just see a bit of of hit in the first quarter, which makes the the the shape throughout the four quarters, a bit flatter and again I'm, probably a little biased lower versus the midpoint of our range.
And then I think it just gives us a good challenge to overcome what happened in February and overcome the increase from the IR am additional <unk> expenses that we see and so you know.
Our goal is to try and be a P.
Handily, what we put out there in guidance, but our models and everything like that or.
In line with what you see out there. So we've got some good challenges ahead of US there good incentives for our guys in the field.
We're up to the task and we continue to hold our feet to the fire.
And our field folks do a fantastic job with that and we're all all the line and very focused on that every every day of the year.
Alright, Thank you all.
Thank you. It appears we have no additional questions at this time, so I'd like to pass the floor back over to Mr. Anderson for any closing comments.
Thanks, everybody appreciate your interest and your time today, and we'll catch you on the first quarter call. Thanks.
Ladies and gentlemen, this does conclude today's teleconference and webcast. We thank you for your participation and you may disconnect. Your lines at this time.
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