Independence Contract Drilling, Inc.

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 the 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 will be an opportunity to ask questions. To ask a question, you may press stars and one on your touchtone phone. To withdraw your question, please press stars and two. Please note this event is being recorded. I would now like to turn the conference over to Philip Choice, Executive Vice President and Chief Financial Officer. Please go ahead, sir.

Good morning, everyone, and thank you for joining us today to assess ICD's fourth quarter 2020 results. With me today is Anthony Gallegos, 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. A number of factors and uncertainties could cause actual results in 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 in our public filings for our full reconciliation of net loss to adjusted net loss, 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. Phillip will go through the details of our financial results for the fourth quarter of 2020. In my prepared remarks today, I want to talk about the progress we've made putting rigs back to work, 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, we've been busy putting the pieces back together after the historic downturn in industry activity during the second and third quarters of last year. Speaking about the fourth quarter specifically, we reported an EBITDA loss, even though we continued to add contracted rigs during the quarter. During the quarter, reactivation costs impacted our results by approximately $700,000. 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 of more rig activity, which manifested itself in a sequential decrease in 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. I want to point out that execution of transactions under this program are totally at our discretion, and as of today, 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, $15 million under our term loan accordion, and the five 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 in 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 2021, we have reactivated an additional three rigs plus an additional rig that will commence operations mid-March. At an expected first quarter exit rate of 12 operating rigs, we will have increased our operating rig count in the past eight months by 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 in these highly competitive times. And that means operating safely with minimal downtime and startup delays. And our operating 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. In fact, we're very proud that during the fourth quarter we were awarded Energy Point Research's Award for Service and Professionalism for the second year in a row. In addition, we've broken several records for our customers, including four during the fourth quarter. For example, we drilled a 15,200 foot well and ten and a half days for one client. We drilled a 5,700 foot lateral in 24 hours for another client breaking the previous record the same rig had just set with the same client. And for a third client we set records for fastest footage drilled in 24 hours and record intermediate to spud times as well. I couldn't be more pleased with this and impressed with our 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 in the Permian, including one in the Delaware and four in the Midland Basin, four rigs working in the Hainesville in East Texas, and with the rig which will begin mobilizing mid-March, we'll have three rigs working in South Texas, including two in the Eagleford. Our market share in the Hainesville is 8.5%. It's 2.6% in the Permian and 9.3% in the Eagleford. We currently do not have any rigs working on federal lands. We're in the final phases of our upgrade campaign. We're all working ICD rigs except 1,000 horsepower AC rig will be equipped with four generators and three mud pumps. In addition, we've deployed three of the 300 series shell drillers you've heard me describe previously. In other words, we have the right rigs for customers today. Those ENPs that demand plenty of hydraulic horsepower powered by generating capacity to run all three mud pumps simultaneously and when necessary, extreme racking and setback capability. We accomplish this with minimal cash outlay, primarily by employing unused equipment, thereby maximizing our returns in this challenging environment. On the day rate front, trough day rates settled in the mid-teens for ICD's 1,500 horsepower pad optimal fleet and slightly lower for our 1,000 horsepower AC rig working. At 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 a positive note, except for these expiring legacy contracts, all recent recontracting efforts have resulted in 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 reactivations in 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 return to active duty. One other point I want to mention, as we move forward, one thing the industry is experiencing is small, discrete delays driving pockets of off-contract time and lower revenue, lower cost standby days. associated with our customers' planning processes. In the current environment, capital allocation decisions by some E&Ps are being pushed more to the last minute, which affects permitting, site construction lead time, and sometimes trickles down to when 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. Phillip will provide more details in his remarks. In terms of day rates in the rig market today, I think it's 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. The 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-reimbursables, remains in the mid-teens. The fragmentation in the business is partly a driver of this factor. The elasticity of demand at lower commodity prices also contributes to the knife fight between service providers chasing work. At sub $50 barrel oil, day rates matter is what we hear from customers. The good news is the longer their overall activity remains depressed relative to historical levels of demand, the greater the likelihood that marginal players in 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. I'm aware of one private drilling contractor that previously offered AC rigs in the South Texas and West Texas markets having gone out of business. I think it's worth noting that we'll 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 as higher upfront capital investment should require higher day rates or longer-term contracts in order to justify the capex and capital investment associated with adding incremental rigs. Look, ICD 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 day rates move up, we can reach back into our inventory of stacked rigs. Like I indicated earlier, industry needs to do a better job at generating sustainable free cash flow, better returns, and eventual profits 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 2021 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 to third pump, fourth engine additions, and for our 300-series rigs, racking capacity additions to the 27,000 to 29,000-foot racking levels. I'd like to close today with a couple of comments regarding ESG. At ICD, we're focused on doing our part toward the industry's efforts. Regarding the E and ESG, all of our rigs are dual fuel capable, and many of them are employing this carbon reducing technology today by using natural gas in 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. Outfitting and running our rigs in this manner not only results in 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 receive their electrical power. We are always looking for other customers that are willing to undertake this same strategy, and we are excited about the prospects for our industry to continue addressing these challenges. Regarding the G and ESG, we've been very forward leaning on the governance front historically, tying a substantial portion of executive comp to quantifiable measures which are closely aligned with our shareholders' interests. ICD's board recently set compensation metrics for 2021, and this year, 100% of the executive team's long-term incentive comp is performance-based and 100% at risk. I point this out because in 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 in only our most economical assets and structure and compensation that's 100% aligned with shareholder interest, including tying TSR metrics not only to a peer group, but to a broader market index across all industries. On the social front, we completed a very successful campaign over the holidays to give back to the communities where we operate through our Santa's Roughneck campaign and other initiatives, including charitable efforts here in Houston, where our corporate headquarters is based. So summing all of this up, I believe ICD is very well positioned to execute operationally as we recover from this unprecedented downturn, and we're on 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 capable and participating alongside our customers in pursuit of ESG initiatives. We're firmly implanted with a strong brand and reputation for providing the safest and most efficient contract drilling services in 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 Phillip so he can walk us through the financial results for the company.

Thanks, Anthony. During the quarter, we reported an adjusted net loss of $16.3 million, or $2.65 per share, and an adjusted EBITDA loss of $1.5 million. Excluded in calculating adjusted net loss are 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, there's nothing unusual about these five rigs. From a technical perspective, they meet the typical definition for super spec rig. However, from a capital investment perspective, these five rigs will require the most investment to reactivate from stack. And when we look forward, even in an improving market, we do not expect all PAT optimal rigs in the U.S. land fleet will resume operations and do not believe that these five rigs will be reactivated unless market improvements exceed our expectations. Thus, we have removed these rigs from our marketed fleet and do not expect they will return to our marketed fleet absent a material change. The second item excluded in calculating adjusted net loss and adjusted EBITDA was approximately $500,000 of costs associated with our equity line of credit all of which were expensed during the fourth quarter for accounting purposes. Now moving on to other items for the quarter. We operated 7.7 average rigs in 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 increases expected in the second quarter. Revenue per day of $16,720 fell sequentially based upon one rig operating on a standby basis for part of the quarter and contract fleet mix associated with additional rig reactivations and prevailing spot rates. We did not record any early termination revenue during the quarter. Cost per day, $13,719 was favorable compared to guidance and reflects economies associated with higher operating days compared to expectations as well as strong cost control. Costs per day exclude approximately $700,000 associated with RIG reactivations and $500,000 fund-absorbed manufacturing overhead costs. As mentioned, SG&A included $500,000 associated with transaction costs related to the equity line of credit. Excluding these costs, SG&A was $2.9 million, including non-cash compensation expense of $400,000, a slight sequential increase relating to professional fees for year-end matters. During the quarter, cash payments for capital expenditures were approximately one and a half million, offset by proceeds from asset disposals of 2.7 million. There's approximately $900,000 of capex accrued at quarter end, which we expect will flow through during the first quarter of 2021. Our backlog at December 31st, 2020 stood at 6.1 million. All of it expires in 2021. Obviously, this is substantially below historical levels, and almost all of our rigs are now operating on short-term pad-to-pad contracts, which we have never included in our reported backlog. As 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 for the time being until we reach a point where day rate and market economics for longer-term contracts make sense for both us and our customer. Moving on to our balance sheet, At year end reported net debt excluding finance leases and net of deferred financing costs of $125.1 million. This 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. Our PPP loan does not reflect any potential forgiveness. A portion of our PPP loan is classified as current based upon anticipated prepayments once the forgiveness process is complete. Based upon revised guidance from the SBA, we currently expect approximately $7.5 million or more of this balance to be forgiven and that 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 an SBA audit of our loan forgiveness calculations and eligibility for the loan, so the actual length of time this process will take and its outcome is currently unknown. Until we have a final forgiveness determination, the full amount of the PPP loan 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. I will go through guidance in a moment, but we also expect to report an EBITDA loss through at least the first quarter of 2021. We also need to cover budgeted CapEx for 2021 and accrued CapEx and AP at year end, about $6.7 million in total, plus 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 $1.5 million of payments on the PPE loan, all totaling about $21 to $22 million in non-operating payments on top of any EBITDA losses. Assuming continued moderate improvements in our operating rate count and modest improvements in spot day rates, perhaps $500 to $750 per quarter, we believe we can approach free cash flow neutrality late in 2021 and improve on that in 2022. But given the levers available to us 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 $15.2 million, including $3.2 million of non-cash compensation expense. Anthony mentioned that all of our 2021 Long-Term Incentive Awards constitute at-risk performance-based compensation. Expense associated with these awards is subject to variable accounting tied to increases or decreases in our stock price and other performance measures. which will create variability between quarters in these reported numbers, as well as our estimates. Our cash-based SG&A expense guidance reflects an increase for resumption of our annual incentive plan, which also is performance-based and at risk. Overall, 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 $100,000 per quarter. Moving on to first quarter guidance. We expect operating days to approximate 923 days, representing 10.3 average rigs working during the quarter. We expect to exit the first quarter with 12 rigs operating. 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 $3,000 and $3,100 per day, representing a slight sequential increase as modest improvements in spot day rates are offset somewhat by the expiration of expiring legacy day rate contracts. Because 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. We expect revenue per day to come in between $14,900 and $15,000 per day, and cost per day to come in around $11,700 and $11,900 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 $700,000 in unabsorbed overhead costs during the quarter. These costs are not included in our top of our cost per day guidance. We expect SG&A expense to approximate $4.1 million. Included in this estimate is approximately $1 million of non-cash compensation expense. Sequential increase in non-cash compensation relates to variable accounting on at-risk performance-based compensation driven by recent increases in our stock price. with the ultimate amount based on our stock price at quarter end, and sequential increases in cash SG&A expense relate to the expected accruals under our annual incentive plan, which also is at risk 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 $100,000. CapEx, we expect approximately two million to flow through our cash flow statement during the quarter. And we also do expect a small seasonal working capital bill associated with the payment of year-end property tax payments, in addition to working capital investment associated with the growing operating rate cap. And with that, I'll turn the call back over to Anthony.

Thanks, Phillip. 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. To ask a question, you may press star then 1 on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then 2. At this time, we'll pause momentarily to assemble our roster. And our first question will come from Ryan Finks with B. Reilly Securities. Please go ahead.

Hey, good morning, guys.

Good morning, Ryan.

I'm just wondering if you could give some more color on rig count for the rest of the year, just based on your discussions with customers. You know, one, do you think now with commodity prices higher, have you had some more discussions about longer-term contracts? And two, if you could just give a little bit more color on pricing and if and when you expect that to finally pick up a little bit.

Sure. 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 in the next week, week and a half. That'll put us at 12. We're on a pathway and very confident in our plan to get to 15 rigs. by the end of the second quarter. I think we have sufficient opportunities. The quality of those discussions is good enough that we have a pretty high level of confidence in 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 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. It's in the rearview mirror now. they are starting to move back up. They're moving up very slowly. But we would need to see this day rate improvement continue in order to justify the capital that's going to be required to start up the rest of those rigs. So our strategy and plan would be, you know, I don't know if it's 15, I don't know if it's 18, but it's somewhere in that range. It will be there mid-year. We're going to pause. We're going to look at where day rates are at that time. I don't expect to necessarily put long-term contracts in place where day rates are or where they're even going to be this summer relative to where we think they're going to be in 22 and beyond. But that's how we're thinking about that. Your question about pricing, it's a function of utilization, as you know. As more rigs go out, it'll give us a better opportunity. to move pricing more. I think 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 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, four gens, and things like that. So we still have a couple quarters to go, I think, before we see any significant momentum. in that area, but I would note that we are seeing price improvement even today.

Great. Thank you for all that detail there. And then for the five rigs that are coming out of the marketed fleet, could you just give some additional color on what your plan is for those rigs, potentially maybe marketing them for sale? And then just more generally, could you talk about how the M&A market looks right now for the drilling rig industry?

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 don't have a future. It's just, again, with the returns-focused orientation which we have today, we are repurposing some equipment. to make the smaller marketed fleet more marketable. So think about mud pumps, obviously engines and things like that. You know, is there a scenario in 22 and beyond where those rigs could become competitive? Again, absolutely. It's going to, as you know, be driven by commodity prices and, of course, demand. 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 that subset of the fleet, and that's where we are. Phillip?

Yeah, I look at it as a capital allocation decision. We looked at that as a rig fleet. We looked at what is reasonable to assume that will go back to work in the future, and none of us can predict exactly what the rig count's going to be. If it goes back to 1,000, I think these rigs would be coming back to work, but that's not our prediction. So, we really looked at that, you know, the specifications of these rigs. There's nothing different about these rigs particularly than our other rigs. It's just at the end of the day, we don't see in a kind of as we look out in the future based on kind of what forecasts are potentially for, you know, rig counts after everything kind of, you know, gets more to a normal basis, you know, these may come back to work. So, that's the decision there. Right now, we have no plans to sell those rigs. So that's really kind of the basis for those decisions.

And Ryan, just on the M&A question, you guys know we've been very vocal about our view and the need for consolidation within the industry. I believe most people understand that the worst is behind us now. As you know, there's been a couple of companies that now 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 people that we would expect to be participating in M&A are now on the other side of the restructuring, that hopefully 2021 will present some opportunities, not just in the rig business, but across oilfield services. We'll continue to pay attention to that. We have a strategy as ICD on a standalone basis. Obviously, we need more scale, more rigs running. We're very confident that given the overhead that we have in place, the infrastructure around that, the systems and processes that underlie it, that ICD is an excellent solution. company and entity to participate in a much-needed consolidation within oilfield services.

Great. Well, thank you guys for taking my questions and hope you're doing well. Otherwise, down in Texas, I'll turn it back. Yes, sir.

Thank you. The next question will come from Daniel Burke with Johnson Rice. Please go ahead. Yeah, good morning, guys.

Morning, Daniel. Morning, Daniel.

I just had a couple of clarifications left. I guess I was still a little unclear. The five rigs, are you going to be utilizing components from those rigs such that you will suppress your maintenance capital requirements this year, or should we consider them to be cold stacked but untouched?

No. To the extent we utilize components, it will be to... 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 call that more growth or capex, if you think about it. We reduce that if we were going to use those parts. Otherwise, they're available for capital spare. I don't think it's going to reduce maintenance capex 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 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 next incremental rigs reactivation cost look like? Just try and understand the day rate environment you'd have to see to move the count beyond that 15 to 18. Okay.

Yeah, so look, we've talked about this. I think it's generally known. We've spent between $300,000 and $600,000 per startup. As we've thought about incremental contracts, we've 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 recover that. Now, obviously, you can't do that long term, but this year, as we think about 2021 in particular, it's a year of transition. It's a year of positioning because, again, our outlook for next year and beyond is better. So 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, you're looking at a multiple of that. It's not $3 million. It's going to depend on how long the rig's been idle. If we have used any of its equipment in 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 100% utilization. But right now, the focus is to get to enough operating scale where we get to cash flow neutrality. That's our goal for this year, and ultimately to generate more positive cash flows 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, small question to ask. When you're in that sort of mid-15-18 rig range, maybe for Phillip, and assuming normalized standby activity, where do you think your operating cost per day is going to be?

Yeah, so assuming there's no cost inflation or anything like that, we would be under $13,000 a day moving all the moving away from the standby things that obviously impact the reported number. But assuming those rigs are operating and we eliminate standby, we would be under $13,000 a day.

Okay. That's helpful. All right, guys. Thanks for letting 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 Gallegos, President and Chief Executive Officer, for any closing remarks. Please go ahead, sir.

Okay. Guys, we sure appreciate you taking a few minutes out of your busy day to dial in today and listen. Appreciate your support of ICD. Wish everyone safety and health here in 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.