Q4 2020 Independence Contract Drilling Inc Earnings Call
Good day and welcome to the independence contract drilling incorporated fourth quarter and year end 2020 financial results Conference call. All participants will be in a listen only mode should you need assistance. Please signal a conference specialist by pressing the star key followed by zero. After today's presentation there'll be an opportunity to ask question.
And to ask a question you May Press Star then one on your Touchtone phone to withdraw your question. Please press Star then two please note. This event is being recorded I would now like to turn the conference over to Philip Choyce Executive Vice President and Chief Financial Officer. Please go ahead Sir.
Good morning, everyone and thank you for joining us today to discuss Icd's fourth quarter 2020 results.
With me today, as Anthony Guy and I guess, our president and Chief Executive Officer.
Before we begin I would like to remind all participants that our comments today will include forward looking statements, which are subject to certain risks and uncertainties and.
Number of factors and uncertainties could cause actual results and future periods to differ materially from what we talk about today.
For complete discussion of these risks we encourage you to read the company's earnings release, and our documents on file with the SEC.
In addition, we refer to non-GAAP measures during the call.
Please refer to the earnings release, and our public filings for a full reconciliation of net loss to adjusted net loss EBITDA.
EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures.
With that I'll turn it over to Anthony for opening remarks.
Hello, everyone and Philip will go through the details of our financial results for the fourth quarter of 2020.
And my prepared remarks today I want to talk about the progress we've made putting rigs back to work [noise] offer some perspective about the current rig market and talk briefly about our progress pursuing our ESG strategy.
So as we exited 2020, we were pleased that the momentum that began at the end of the third quarter continued through the fourth quarter and into the new year as you'll see and we've been busy putting the pieces back together after the historic downturn and industry activity during the second and third quarters of last year.
Thinking about the fourth quarter, specifically and we reported an EBITDA loss, even though we continue to add contracted rigs during the quarter during the quarter, our reactivation cost impacted our results by approximately $700000.
Our financial results were bolstered by our cost rationalization and cost control efforts implemented last year and better absorption of fixed and support cost as a result, and more rig activity, which manifested itself and a sequential decrease and our per day operating cost.
In addition to significantly improving our operating rig count during the quarter, which I'll discuss shortly we continue to improve our overall financial liquidity.
We entered into a $5 million equity line of credit agreement that will allow us to sell stock and add liquidity.
Want to point out that execution of transactions under this program are totally at our discretion and as at the day.
We have not yet executed any transactions.
Overall liquidity at quarter end stood at $39 8 million consisting of $12 3 million of cash.
On hand, $7 5 million of availability under our Undrawn revolver and $15 million under our term loan accordion and the 5 million available under the new equity line of credit.
As mentioned on prior conference calls as rigs come back to work the borrowing base under our revolver grows and again becomes a source of capital for us and you're seeing that transpire now as our rigs go back to work revolver availability increased 44% since the end of the third quarter and we expect to continue to see sequential improvements and our borrowing base.
As market conditions improve and our rig count increases.
During the fourth quarter, we reactivated three additional drilling rigs and since the beginning of 'twenty 'twenty, one we have reactor and reactivated and additional three rigs plus an additional rig that will commence operations and mid March.
And an expected first quarter exit rate of 12 operating rigs and we will have increased our operating rig count and the past eight months about 300%.
Throughout this ramp up our operations support and corporate teams performed exceptionally well when you reactivate rigs out of stack you must navigate the unexpected and you still must hit the ground running for your client, particularly and these highly competitive times and that means operating safely with minimal downtime and startup delays and our opt.
<unk> teams have done exactly that and more while tripling the size of our operating fleet over a couple of quarters all of our reactivated rigs have been reactivated safely on time on budget and with very minimal downtime.
And our operations are exceeding our customers' expectations and in fact, we're very proud that during the fourth quarter. We were awarded energy point Research is award for service and professionalism for the second year in a row. In addition, we broke and several records for our customers, including four during the fourth quarter and for example, we drilled.
15200 foot, well and 10 and a half days for one client, we drilled 5700 foot lateral and 24 hours for another client breaking the previous record the same rig and just sat with the same client.
And for a third client we set records for fastest footage drilled and 24 hours and record intermediate to spud times as well I couldn't be more pleased with this and impressed with their operations given we only had an average of 7.7 rigs working during the quarter.
As a consequence of this positive contracting momentum we now have rigs operating in three primary basins within our target market as of today, we have five rigs working and the Permian, including one in the Delaware and four in the Midland Basin four rigs working in the Haynesville and East Texas.
And with the rig which will begin mobilizing mid March well have three rigs working and south Texas, including two in the Eagle Ford.
Our market share and the Haynesville is eight 5%.
It's two 6% and the Permian and nine 3% and the Eagle Ford. We currently do not have any rigs working on federal lands.
We're in the final phases of our upgrade campaign, where all work and ICD rigs, except 1000 horsepower AC rig will be equipped with four generators and three mud pumps.
In addition, we deployed three of the 300 series shale Drillers, you've heard me described previously and.
In other words, we have the right rigs for customers today, those e&ps that demand plenty of hydraulic horsepower powered by generating capacity to run all three mud pumps and simultaneously and when necessary extreme racking and setback capability. We accomplished this with minimal cash outlay, primarily by employing unused equipment, thereby maximized.
And our returns in this challenging environment.
On the day rate front trough day rates settled and the mid teens for ICD 1500 horsepower pad optimal fleet and slightly lower for our 1000 horsepower AC rig working.
These day rates, new contracts and renewals have primarily been on a pad to pad basis. Thus our reported backlog at year end was very low compared to historical levels.
By year end 2020, all of our higher day rate legacy contracts, which we executed pre pandemic had expired on.
And on a positive note except for these expiring legacy contracts. All recent re contracting efforts have resulted and day rate increases over trough levels, but we still have a ways to go.
We believe however that most of the easy low hanging rig reactivation and the U S land rig fleet have occurred.
We believe industry wide reactivation costs are higher for rigs stacked over nine months, thereby requiring higher day rates to generate economic returns as rigs returned to active duty.
One other point I want to mention as we move forward one thing and the industry is experiencing a small discrete delays driving pockets of off contract time, and lower revenue lower cost standby days associated with our customers' planning processes and.
And the current environment capital allocation decisions by some e&ps are being pushed more to the last minute, which affects permitting and site construction lead time, and sometimes trickles down and to win our mobilization can commence.
I bring this up only to highlight that we expect to have more lower revenue lower cost standby days during the first quarter of 2021 as a result of this.
Philip will provide more details in his remarks.
In terms of day rates and the rig market today I think its generally understood that pricing is not where it needs to be for our industry to be a viable investment opportunity there have been too many available rigs chasing too few opportunities post pandemic.
High fixed cost of running a drilling company, coupled with undercapitalized balance sheets compel too many drilling contractors to chase incremental work at the expense of day rate spot market day rates ex Reimbursable remains and the mid teens the fragmentation and the business is partly a driver this factor the elasticity of demand at lower commodity prices also.
To the knife fight between service providers chasing work.
And at sub $50 barrel day rates matter is what we hear from customers.
The good news is the longer that overall activity remains depressed relative to historical levels of demand the greater the likelihood that marginal players and the day work contract business will struggle to arrange capital investment required to fund upgrades mobilizations and overall startup expense, including working capital for incremental rigs.
And I'm aware of one private drilling contractor that previously offered AC rigs and the South, Texas and West, Texas markets, having gone out of business.
I think it's worth noting that will reach the end of the easy upgrades later this year.
Many contractors have taken equipment from idle rigs to upgrade and reactivate rigs since the rig count bottomed last summer.
This is an important point is higher upfront capital investments should require higher day rates are longer term contracts in order to justify the capex and capital investment associated with adding incremental rigs.
And I say day is no different except that we focus on these drivers every day. It is for this reason that we are reducing our marketed supply.
This will allow us to focus on a smaller fleet and be more discerning when committing to starting up additional rigs.
I think for ICD at current spot rates. We reached this point between 15 and 18 rigs contracted beyond this point the investment required does not make sense at current market day rates. Instead, we can generate more operating margin running fewer rigs at higher day rates and once a day rates move up we can reach back into our inventory of stacked rigs.
Like I indicated earlier, our industry needs to do a better job at generating sustainable free cash flow better returns and eventual profits and.
In order to attract and retain talent and investors to oilfield services.
Continuing with this returns focused theme and moving on to governance matters Icd's Board has approved the capital expenditure budget for 'twenty and 'twenty, one of $5 8 million a significant reduction compared to the $14 2 million spent last year. Most of this is maintenance with the remainder principally allocated that third pump fourth engine.
<unk> and for our 300 series rigs and racking capacity additions to the 27020 9000 foot racking levels.
I'd like to close today with a couple of comments regarding ESG and ICD, we're focused on doing our part towards the industry's efforts regarding the E. N E. S. G. All of our rigs are dual fuel capable and many of them and are employing this carbon reducing technology today by using natural gas and combination with diesel as feedstock for our generators.
More impressively earlier this month, we commenced another ICD rig, which is operating using electricity from the utility grid for power to run the rig and its equipment and.
Outfitting and running our rigs in this manner, not only results and cost savings for our customers, but also eliminates 100% of the pollution at the pad site compared to running four generators on a drilling location, which is how rigs typically received their electrical power and we're always looking for other customers that are willing to undertake this same strategy and we're excited about the prospects for.
And our industry to continue addressing these challenges.
Regarding the G and ESG and we'd been very forward leaning on the governance front and historically, including tying a substantial portion of executive comp to quantifiable measures, which are closely aligned with our shareholders' interest.
Icd's Board recently set compensation metrics for 'twenty and 'twenty, one and this year, a 100% of the executive team's long term incentive comp is performance based and 100% at risk.
And I point this out because on a returns based world I think ICD is pulling all the levers available to drive returns and align ourselves with our shareholders. We're rationalizing assets investing and only our most economical assets and structure and compensation, that's 100% aligned with shareholder interest, including tying tsi metrics.
Not only to our peer group, but to a broader market and dragged index across all industries.
On the social front, we completed a very successful campaign over the holidays to get back to the communities, where we operate through our Santa's rough net campaign and other initiatives, including turbo charitable efforts here in Houston, where our corporate headquarters is based.
So some and all of this up I believe ICD is very well positioned to execute operationally as we recover from this unprecedented downturn and we own a pathway to drive returns for all of our stakeholders our financial.
Flexibility has improved since the 2020 downturn and our management team remains incentivized accordingly to focus on cash flow generation and financial returns over the longer term with our management team winning only if our shareholders do.
Our systems and processes, which support our operations are best in class and our rig fleet is young flexible and engineered to maximize manufacturing efficiencies for our customers. We're breaking records, winning accolades for professionalism and service and meeting and exceeding our customers' expectations across the fleet every day.
Our rigs are drilling optimization, and capable and participating alongside our customers and pursuit of ESG initiatives, we're firmly implanted with a strong brand and reputation for providing the safest and most efficient contract drilling services and north America's most prolific oil and gas producing regions, which reside in Texas and the contiguous states.
And with that I'll turn the call back over to Philip So he can walk us through the financial results for the company.
Thanks, Anthony during the quarter, we reported and adjusted net loss of $16 $3 million or $2 65 per share and adjusted EBITDA and an adjusted EBITDA loss of $1 $5 million.
Excluded in calculating adjusted net loss of two discrete items.
First we recorded an impairment expense of $24 $4 million associated with five rigs and other ancillary equipment.
From a rig configuration perspective perspective, theres nothing unusual about these five rigs and from a technical perspective to meet the typical definition for Super spec rig however from a capital investment perspective. These five rigs were required the most investment to reactivate from stack and we look and when we look forward even in an improving market.
We do not expect all pad optimal rigs and the U S land fleet will resume operations and do not believe that these five rigs will be reactivated must market improvements exceed our expectations. Thus we removed these rigs from a markedly and do not expect they will return to our marketed fleet absent a material change.
Second item excluded in calculating adjusted and net loss and adjusted EBITDA was approximately $500000 of costs associated with our equity line of credit and all of which will be where expense during the fourth quarter for accounting purposes.
Now moving on to other items for the quarter, we operated seven seven average rigs and line with guidance provided on our prior conference call, we expect utilization to increase sequentially by over 30% during the first quarter of 2021 compared to fourth quarter averages with further sequential increase as expected and the second quarter.
Revenue per day of 16000, and $720 fell sequentially based upon one rig operating on a standby basis for part of the quarter and contract fleet mix associated with additional rig reactivation and the prevailing spot rates we.
And did not record any early termination revenue during the quarter.
Cost per day, 13000, and $719 was favorable compared to guidance and reflects economies associated with higher operating days compared to expectations as well as strong cost control.
Cost per day exclude approximately $700000 associated with rig reactivation and $500000 unabsorbed manufacturing overhead costs.
As mentioned SG&A included $500000 associated with transaction costs related to the equity and lot of credit. Excluding these costs SG&A was $2 9 million, including noncash compensation expense of $400000, a slight sequential increase related to professional fees for year and matters.
During the quarter cash payments for capital expenditures were approximately $1 5 million offset by proceeds from asset disposals of $2 7 million.
It was approximately $900000 of capex accrued at quarter, and which we expect will flow through during the first quarter of 2021.
Our backlog at December 31, $2026 1 million and all of it expires in 2021.
Obviously this is substantially below historical levels levels and I'm also all of our rigs on operating on short term pad to pad contract.
But we have never included on a reported backlog is there.
Anthony mentioned current spot day rates remain depressed and with our expectation for improvement throughout the remainder of the year. We believe our reported backlog will remain depressed from the time being until we reach a point where day rate and market economics for longer term contracts makes sense for both us and our customer.
Moving onto our balance sheet at year end reported net debt, excluding finance leases and net of deferred financing costs of $125 1 million.
Net debt is comprised of our term loan and $10 million PPP loan.
Finance leases reflected on our balance sheet at quarter end were approximately $7 9 million.
P. P loans does not reflect any potential forgiveness, a portion of our P. P loans classified as current based upon anticipated prepayments once the forgiveness process is complete.
Based upon refi revised guidance from the SBA. We currently expect approximately $7 odd million or more of this balance to bergevin and net payments on the unforgiven portion to begin during the fourth quarter of 2021 and continue through April 2022.
However, we do expect to go through and SBA audit of our loan forgiveness calculations and eligibility for loans. So the actual and length of time. This process will take and its outcome is currently unknown.
Until we have a final forgiveness determination full amount on the PPP loans will remain on our balance sheet.
Anthony mentioned at year end, we had total liquidity of $39 8 million.
Looking at the sufficiency of this we obviously reported an EBITDA loss for the third and fourth quarters of 2020 and are generating negative free cash flow.
And we'll go through guidance and a moment, while we also expect a reported an EBITDA loss through at least the first quarter of 2021.
We also need to cover budgeted capex for 2021, and accrued capex and IP at year, and about $6 $7 million and total plus cash and cash interest payments of approximately $9 million, assuming we pick one quarter of interest payments this year and finance lease payments of approximately $3 5 million.
And perhaps one and a half million of payments on the P. P loans.
All totaling about $21 million to $22 million and nonoperating payments on top of and the EBITDA losses.
Assuming continued moderate improvements and our operating rig count and modest improvements and spot day rates, perhaps $500 to $750 per quarter. We believe we can approach free cash and.
Cash flow neutrality late in 2021 and improve on that and 2022.
But given the levers available to pull at this time, we are very comfortable with our financial liquidity position.
Now moving on to fiscal 2021, and first quarter guidance.
On fiscal 2021 numbers as mentioned our Capex budget is $5 8 million comprised primarily of maintenance items.
Our budget for SG&A is $5, $15 2 million, including $3 $2 million and noncash compensation expense.
Anthony you mentioned that all of our 2021 long term incentive awards constitute at risk performance based compensation.
<unk> expense associated with these war. These awards is subject to variable accounting and tied to increases or decreases and our stock price and other performance measures, which will create variability between quarters and these reported numbers as well as our estimates.
Cash based SG&A expense guidance reflects an increase from the resumption of our annual incentive plan, which also is performance based on net risk.
And we're all approximately $4 $5 million of our annual SG&A expense estimate is tied to at risk performance based compensation, which may or may not be realized if market conditions do not improve or if they deteriorate or we do not meet our financial and operational goals.
Depreciation expense for the year, we approximated about $10 million per quarter interest expense about $3 8 million per quarter and tax expense should again be de minimis, perhaps a $100000 per quarter.
Moving on to first quarter guidance.
We expect operating days to approximate 923 days, representing 10, three average rigs working during the quarter, we expect to exit the first quarter with 12 rigs operating and <unk>.
Approximately 100 of our revenue days during the quarter will be earned on a reduced standby basis.
We expect margin today per day to come in between 3030 $100 per day, representing a slight sequential increase is modest improvements and spot day rates are all sorts offset somewhat by the exploration of expiring legacy day rate contracts.
It goes a little over 10% of these revenue days will be earned on a standby basis, both our expected revenue per day and cost per day will be sequentially lower.
Expect revenue per day to come in between 14000 $915000 per day and cost per day to come and around 11000 and $711900 per day and these per day amounts exclude pass through revenue and expenses.
We also expect to incur an additional $1 2 million associated with the four rigs reactivating during the first quarter and $700000 and unabsorbed overhead costs. During the quarter. These costs are not included net and our top of our cost per day guidance.
We expect SG&A expenses to approximate $44 $1 million.
And concluded in this estimate is approximately $1 million of noncash compensation expense.
Sequential increase in non cash compensation related to variable accounting on at risk performance based compensation driven by recent increases and our stock price with the ultimate amount based on our stock price at quarter end.
The sequential increases in cash SG&A expense relate to the expected accruals under our annual incentive plan, which also is at risk and tied to achieving predetermined performance measures.
For the quarter, we expect interest expense and depreciation expense to be approximately $3 8 million and $10 million, respectively and tax expense to be approximately $100000.
Capex, we expect suddenly too we expect approximately $2 million to flow through our cash flow statement during the quarter.
And we also do expect a small seasonal working capital build associated with the payment of year and property tax payments and addition to working capital investment associated with the growing operating rig count.
And with that I'll turn the call back over to Anthony.
Thanks, Philip I have no further comments at this time operator, let's go ahead and open up the line for questions.
Will do we will now begin the question and answer session.
Ask a question and you May Press Star then one on your Touchtone phone if youre using a speakerphone. Please pick up your handset before pressing the keys to withdraw your question. Please press Star then two at this time, well pause momentarily to assemble our roster.
And our first question will come from Brian <unk> with B Riley Securities. Please go ahead.
Hey, good morning, guys.
Ryan Good morning, Ryan.
I'm just wondering if you could give some more color on our rig count for the rest of the year just based on your discussions with customers.
One do you think now with commodity prices higher.
Have you had some more discussions about longer term contract.
And two if you could just give a little bit more color on on pricing and if and when do you expect that to finally pick up a little bit.
Sure.
And I appreciate the question Ryan.
First as we think about where we are right now we're at 11 today, the 12th rig will start mobilizing out of Houston here and the next.
We can have the that'll put us at 12, we're on a pathway and very confident and our plan to get to 15 rigs by the end of the second quarter and think we have a.
And opportunities the quality of those discussions is good enough that we have.
And at pretty high level of confidence and that.
As we think about rig count beyond that it's really going to become a function of where day rates are at that time relative to the capital investment that we're going to have to make I think.
And I think this is true of a lot of drilling contractors as we continue to reach deeper into the inventory into rigs that have been stacked for nine months 12 months, plus, especially considering equipment upgrades and things like that that must be done to be competitive in today's market.
We need to see day rates move from where they are right now we tried to signal and tell you guys that we saw day rates hit a bottom and it's in the rearview mirror now they are starting to move back up and moving up very slowly but we.
We would need to see.
This day rate improvement continue in order to justify the capital was going to be required to start up the rest of those rigs. So our strategy and plan would be I don't know if its 15 I don't know if it's 18, but it's somewhere in that range.
I'll be there mid year, we're going to pause, we're going to look at where day rates are at that time.
And I don't expect to necessarily put long term contracts in place where day rates are or where they are even going to be this summer relative to where we think they're going to be in 'twenty two and beyond.
But.
That's how we're thinking about that your your question about pricing.
It's a function of utilization as you know.
You know as more rigs go out.
It'll give us a better opportunity to move pricing more.
Historically people have thought of that threshold at around 80% utilization I would point out that it's not 80% of the total supply that's out there, but it's going to be 80% of the.
Of the supply that is in high demand at this time, which of course are the super spec rigs rigs that are outfitted with three mud pumps for Jens and things like that.
So still have a couple of quarters to go I think before we see any significant momentum and then area, but I would note that we are seeing price improvement even today.
Yes.
Great. Thank you for all that detail there and then for the five rigs that are coming out of the marketed fleet.
And you just give some.
Additional color on what your plan is for those rigs potentially may be marketing them.
For sale.
And then just more generally could you talk about.
And how the M&A market looks right now.
Further drilling break industry.
No.
Sure.
I'll start with and Philip May have some comments he'd want to add on the five rigs coming out of the market.
It's not that they're they don't have a future. It's just again with the roof returns focused orientation, which we had the day we are repurposing some equipment.
To make the the smaller marketed fleet more marketable so think about mud pumps.
Obviously engines and things like that.
Is there a scenario in 'twenty, two and beyond where were those rigs could become competitive again, absolutely. That's going on as you know drip would be driven by commodity prices and of course demand.
<unk>.
But that's how we're thinking about those rigs we just wanted to get more focused on a smaller marketed fleet and try to generate as much free cash flow as we can with with that subset of the fleet and and that's where we are and Phil Yeah, I look at it as a capital allocation decision, we looked at that our rig fleet and we looked at.
What is reasonable to assume that we'll go back to work and the future and none of us can predict exactly what the rig count is going to be if it goes back to 1000, I think these rigs would be coming back to work, but that's not our prediction.
So we really looked at that.
The specifications of the drinks there's nothing.
There is nothing different about these rigs, particularly than our other rigs and it's just at the end of the day, we don't see and a.
Kind of as we look out.
And the future based on kind of what forecasts are potentially four rig counts after everything got it.
It gets more to a normal based on these may come back to work. So that is decision there right now we have no plans to sell those rigs.
And.
So that's really kind of on the basis for from those decisions and.
And Ryan just on the M&A question I mean.
You guys know, we've been very vocal about our view and and the need for consolidation within the industry I believe most people.
I understand that the worst is behind us now.
As you know there has been.
A couple of companies that now have have come out of the restructuring process. So as we think about.
The better macro environment, certainly the better outlook for the industry and the fact that some some people that we would expect to be participating and M&A are now on the other side of the restructuring that are hopefully 'twenty and 'twenty. One we'll present some opportunities not just in the rig business, but across oilfield services. So we will continue to pay attention to that.
And we we have a strategy.
And as ICD on a standalone basis, obviously, we need.
More scale more rigs running and we're very confident that given the overhead that we have and place the infrastructure around that the systems and processes that underlie it that Oh ICD is an excellent.
The company and and entity to participate and in a much needed consolidation within oilfield services.
Great well. Thank you guys for taking my questions and and hope you're doing well otherwise down in Texas, and I'll turn it back and get there. Thank you.
The next question will come from Daniel Burke with Johnson Rice. Please go ahead.
Yeah, Good morning, guys.
Good morning, Daniel Daniel.
I just had a couple of clarifications left I guess I was still a little unclear the five rigs and.
Or are you going to utilize and components from those rigs such that you will suppress your maintenance capital requirements. This year or should we consider them to be be cold stacks and untouched.
No. These are.
To the extent, we utilized components it will be too if we're putting a third pump fourth engine on one of the other 25 rigs it'll reduce that kind of what I would call I'll call them more growths of Capex. If you think about it we reduced that if we're going to use those parts otherwise are available for capital spare and I don't think it's going to reduce maintenance.
And capex on on any of the rigs that we operate.
Okay. That's helpful.
And then Anthony I thought your comment on sort of looking to get to 15 to 18 rigs whenever that might be and and then taking a pause made sense, but.
What do you think your reactivation costs are per rig once you get to that threshold I mean, what does that what does that next incremental rigs reactivation costs look like just try and understand the day rate environment you'd have to see two two moved account beyond that 15 to 18.
Yes, so we.
We've talked about this I think it's generally now and we've spent between 300 and $600000 per start up as we thought about incremental contracts. We wanted to ensure that at a minimum over the primary term of any contract that we take today that on a cash on cash basis, we at least <unk>.
Cover that and obviously you can't do that long term, but this year as we think about 'twenty 'twenty. One in particular, it's a year of transition into Europe positioning because again our outlook for next year and beyond is is better so yes.
And as we think about that next tranche and I don't know if it's the 18th rig the 19th rig or the 17th rig yeah.
Youre looking at a multiple of that it's not $3 million, it's going to depend on how long the rigs been idle if we have.
Used any of its equipment and upgrading another rig and stuff like that but internally we have a strategy from an equipment standpoint, we know exactly what needs to be done to get to 20 rigs and ultimately back to a 100% utilization but.
Right now the focus is to get to.
And up operating scale.
Where we get to cash flow neutrality.
That's our goal for this year and ultimately generate more positive cash flow. So that we can do some other things with that but hopefully that answers your question.
Yeah. It does and then maybe just a final again, it's small question to ask when you were in that sort of mid 15 to 18 rig range, maybe fulfill up and assuming you know normalized standby activity, where where do you think your operating cost per day is going to be.
Yeah, so assuming theres no cost inflation or anything like that we would be under $13000 a day getting moving all of the moving away from the standby things that obviously.
Doug.
Impact that reported number but something on those rigs are operating and we eliminate standby and we would be under $13000 of debt.
Okay. That's helpful. Alright, guys. Thanks, Thanks for let me ask a few.
Great. Thank you Daniel.
This concludes our question and answer session I would like to turn the conference back over to Anthony Guy Eagle's, President and Chief Executive Officer for any closing remarks. Please go ahead Sir.
Okay. I guess, we sure appreciate your taking a few minutes out of your busy day to dial and today and listen and I. Appreciate your support of ICD wish everyone safety and healthy healthier and the new year and we'll sign off from here now. Thank you all.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
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