Independence Contract Drilling, Inc. (NYSE:ICD) Q3 2022 Earnings Conference Call November 1, 2022 12:00 PM ET
Company Participants
Philip Choyce – Executive Vice President and Chief Financial Officer
Anthony Gallegos – President and Chief Executive Officer
Conference Call Participants
Don Crist – Johnson Rice
Steve Ferazani – Sidoti
Jeff Robertson – Water Tower Research
Dave Storms – Stonegate
David Marsh – Singular Research
Operator
Good day, and welcome to the Independence Contract Drilling Third Quarter 2022 Results Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions]. Please note, this event is being recorded.
I would now like to turn the conference over to Philip Choyce, Please go ahead.
Philip Choyce
Good morning, everyone, and thank you for joining us today to discuss ICD’s third quarter 2022 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 a 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 and adjusted EBITDA and for definitions of our non-GAAP measures.
And before I turn over to Anthony, I just want to make one comment. We did file with the SEC today, along with our press release updated investor presentation which will be available on our website as well. So we encourage people to go take a look at that when they have a chance.
And with that, I’ll turn it over to Anthony for opening remarks.
Anthony Gallegos
Thank you, Philip. Hello, everyone. Thank you for joining us today for our third quarter earnings conference call. During my prepared remarks today I want to focus on a couple of key topics.
First, the significant margin expansion that continued during the third quarter and our prospects for continued margin progression, which are bright. Second, operational achievements during the third quarter and our outlook for additional rig reactivations. And third, some overall strategic objectives we are laying the groundwork for as we look forward into 2023 and beyond.
The first just a few comments on the quarter. Overall ICD’s third quarter results came in well ahead of expectations on revenues, margins and adjusted EBITDA. We’ve reported revenue per day of $28,646 and margin per day of $11,341. This is a 15% increase in revenue per day and a 27% increase in margin per day, compared to second quarter reported results.
We had some one time items affect our reported SG%A numbers during the quarter, which Phillip will go through in his prepared remarks. But overall, we’re pleased to report third quarter adjusted EBITDA of $12.5 million, which is a 35% increase from the second quarter, also higher than expectations.
I want to point out that our reported revenue per day and margin per day are all records for ICD. To put this quarters performance into perspective, the only time ICD has reported higher quarterly adjusted EBITDA was during the fourth quarter of 2018 when all 32 of our rigs were operating.
We only operated about 18 rigs this quarter, which given we believe we’re still in the early innings of this upcycle really highlights how much stronger and well-positioned ICD is today than we were at any time in our history. We look forward to opportunities to report record EBITDA in the coming quarters and beyond. More excitingly, we expect this momentum to continue.
Market conditions and demand for our pad-optimal, super-spec rigs continues to be robust. And we are forecasting meaningful significant improvements in margin per day, driven by continued recognition of the value provided by our rig fleet, including increasing market penetration of our 300 series rigs, our 200 to 300 series conversion opportunities, and additional plan rig reactivations, which are in the pipeline.
Phillip will provide more detailed guidance for the fourth quarter, but I wanted to highlight that we currently expect our margin per day to increase to between $12,500 and $13,000 per day. And looking into the first quarter, we expect March per day to further increase over reported third quarter results by 28% to 32%.
Now it’s not just our rig margins that are on par with or exceeding those of our larger public company peers. We believe our operations and the value we provide to our customers are best in class as well. So to provide us some tangible evidence of this, we were proud during the third quarter to be the highest rated U.S. land drilling contractor for service and professionalism by energy point research, the leading third party industry source for such information.
This is the fifth consecutive year, we have received this cabinet award. And that same poll of the E&P companies operating in the United States, we were also one of three drilling contractors recognized for overall customer satisfaction. I point this out because we talk a lot about our rigs and our 300 series rig penetration, but it’s our operating and field personnel who work hard every day to exceed our customers expectations at the well-site which ultimately is driving so much of ICD success.
During the third quarter, we reactivated our 18th rig, which went to work under a one year contract. Our 19th rig is mobilizing now also under a one year contract and our 20th rig is contracted and scheduled for mobilization later in the fourth quarter. Both of these additional rigs are going to work in the Haynesville and will generate revenue per day in the high 30s, allowing us to achieve simple payback both rigs reactivation CapEx in less than one year. We have slated our 21st and 22nd rigs for reactivation during the first quarter next year, and reactivation work is already underway.
In our last call, I mentioned the 200 to 300 Series conversion program, which we had commissioned. The first conversion is in progress as we speak for an existing customer of ICD and will be completed later this week.
We have accomplished so much this year and I couldn’t be more proud of how our operations and field personnel have continued to deliver high levels of customer service and performance, which our customers have come to expect from ICD. This is especially noteworthy given the unprecedented challenges involving the labor market and supply chain, which continued to play the global business community.
I want to touch on contract backlog. While our strategy thus far in the recovery has been on securing shorter term pad-to-pad contracts, as day rates have continued to strengthen and accelerate over the last three or four months. We have begun increasing our backlog of term contracts when it makes sense for both ICD and our customer.
Since the second quarter, we’ve increased our backlog 87% to $102 million. Approximately 69% of this backlog extends into 2023. We did not have to cut our rates to secure this backlog. In fact, our backlog extending into 2023 is priced at approximately 35,300 per day, the equivalent of over $17,500 of margin per day based upon third quarter cost day metrics
All of our term contracts contain margin protection features that protect our contracted margins against labor and other inflationary costs increases. This 2023 backlog pricing gives us a great deal of confidence about further margin progression beyond the first quarter 2023 guidance I just provided.
While we are increasing our contractual backlog, we are not calling the top of the market for day rate progression by any means. And right now most of our rigs will reprice at least once more over the next three to six months.
Instead, we are laying on some contract backlog, because as we think about the large capital investments now required to reactivate rigs and consider the significant margin generating opportunities available in our market today, we feel like it makes sense for a portion of our available days to be termed up.
This approach will provide us with continued exposure to future increases in margin per day opportunities, meanwhile, helping to lock in a portion of our future cash flow to help position us regarding our near and longer term strategic initiatives.
As we think about additional rig reactivations and conversions beyond our 22nd rig, we’ll be balancing a variety of strategic factors. First and foremost, we’ll continue to look for full contractual payback for all rig reactivations and conversions, essentially what we’ve been doing.
In addition, we will look to balance the timing of these projects against several competing factors including our level of contractual backlog, our desire to reduce or eliminate future dilution from additional PIK interest, especially considering the rising rate environment we’re in and expected to persist.
Working capital liquidity and evaluating where we are in terms of marketing and contract windows for additional rigs, which we believe will be anchored around our customers annual budgeting cycle based on what we’ve seen here in the back half of this year.
I bring this up because while we are doing the things necessary today to put ourselves in a position to be able to reactivate our 23rd and 24th rigs during the summer of 2023, we also may consider pushing those reactivations toward the end of 2023 if it allows us for example, the ability to stop PIK interest earlier than we previously indicated without sacrificing plan working capital improvements.
Does that bring these prepared opening remarks to a close, I want to say that in ICD, we’re very focused on creating a pathway toward steadily decreasing our net debt position as we move towards the refinancing window for our convertible notes.
One of our long term goals is to reduce our net debt to adjusted EBITDA ratio meaningfully. We intend to do this through a combination of increasing adjusted EBITDA and accompanying free cash flow generation as we build our operating scale, and eventually slow our investments and additional rig reactivations.
For reference, we are currently at 3.41 times lever on an annualized basis using our third quarter results. So while we have some work to do in this regard, our forward visibility relating to rig reactivations and margin progression gives us a great deal of confidence that we will make meaningful progress towards this goal in 2023 and beyond.
I’ll make some additional concluding remarks, but right now, I want to turn the call over to Philip to discuss financial results and outlook in a little bit more detail.
Philip Choyce
Thanks, Anthony. During the quarter we reported an adjusted net loss of $4.8 million or $0.35 per share, and adjusted EBITDA of $12.5 million. We operated 17.4 average rigs during the quarter. Anthony previously mentioned our revenue per day and margin per day metric, so I will not focus on those during my prepared remarks.
SG&A costs were $7 million, which included approximately $1.7 million of stock based and deferred compensation expense. But cash SG&A and stock-based comp expense were higher than guidance do a couple of items.
Cash SG&A was negatively impacted approximately $300,000 by dispute settlement and sequential increases in cash SG&A over the second quarter also were driven by higher incentive compensation accruals based upon improvements in the company’s financial performance, and increases in stock based compensation expense related to full quarter expensing of awards granted in June of this year,
Interest expense during the quarter aggregated $8.1 million. This included $2 million associated with non cash amortization of deferred issuance costs and debt discount, which we excluded when presenting adjusted net income. We paid accrued interest on our carnival convertible notes and tied at the end of the quarter.
Tax Benefit for the quarter was $700,000. During the quarter cash payments for capital expenditures, net of disposals were approximately $9.4 million. Breaking this CapEx out approximately 54% related to rig reactivations and 200 to 300 series conversions. 39% related to maintenance CapEx and 5% related to investments in drill pipe capital inventory and spares.
CapEx is trending higher based upon supply chain constraints causing us to bring forward drill pipe and other capital spare purchases, as well as rig reactivation expenses. Of course, there also inflationary pressures. In particular, we ordered earlier than expected long lead time items for our 21st and 22nd rigs during the quarter aggregating approximately $5 million.
Moving on to our balance sheet adjusted net debt was $170.4 million at quarter end. This amount represents the face amount of our convertible notes and borrowings on our ABL and ignores impacts from debt discounts, deferred financing and finance leases.
We did not issue any shares on our ATM program during the quarter. Our financial liquidity at quarter end was $27.5 million comprise the $7.6 million of cash on hand and $19.9 million available under our revolving credit facility.
Moving on to fourth quarter guidance. We expect operating days to approximate 1,690 days, representing 18.4 average rigs working during the quarter. We expect to exit the year with 20 rigs operating and our 21st and 22nd rigs reactivating during the first quarter of 2023 or potentially early second quarter in the case of the 22nd rig.
We expect margin per day to come in between $12,500 and $13,000 per day. We expect revenue per day to come in between $30,100 and $30,300 per day, with many of the day rate increases on contract rolls, only partially benefiting the fourth quarter. Cost per day is expected to range between $17,300 and $17,600 per day.
Based on contracts in hand and assuming spot market pricing and operating costs remain stable. Right now, we would expect first quarter 2023 margins to come in between $14,500 and $15,000 per day. Unabsorbed overhead costs for the fourth quarter will be about $600,000 and are not included in our cost per day guidance.
We expect fourth quarter cash SG%A expense to be approximately $5 million, stock-based compensation expenses expect to be approximately $1.7 million. We expect interest expense to approximate $8.2 million. Of this amount approximately $2 million will relate to non cash amortization of deferred financing and debt discounts.
Depreciation expense for the fourth quarter is expected to be flat with a third quarter benefit. We expect any tax expense or benefit during the fourth quarter to be net visible. For capital expenditures we expect approximately $13.5 million net of dispositions to flow through our cash flow statement during the fourth quarter.
The majority of this will relate to the completion of our 19th and 20 rigs, as well as the acceleration of the purchase of long lead time items for our 21st and 22nd rigs. Some also relates to upgrades for which we will be reimbursed by customers.
With that, I’ll turn the call back over to Anthony.
Anthony Gallegos
Thanks Philip. Before opening up the call for questions, I want to briefly summarize ICD strategic positioning and what I think it means for ICD stockholders. As we think about this positioning, I think it’s important to highlight how much we’ve truly transformed our company thus far, and the opportunities for our investors going forward as we round out 2022 and step into 2023.
First, our utilization and margin growth coming out of the pandemic is best-in-class. Since coming off the pandemic bottom, we’ve started up more rigs than anyone else in the contract drilling industry as a percentage of each contractors working fleet at the pandemic bottom.
Also, today, our daily rig margins are the best in ICD’s history and are on par with and exceeding some of our larger company peers, as we continue to earn recognition from our customers for industry leading customer service and professionalism.
We have the youngest we believe the best-in-class rig fleet. The market for pad-optimal super-spec rigs is as tight as we’ve ever seen. And ICD is one of only a few drilling contractors with visible excess rig capacity that can be economically reactivated into this market. We continue to demonstrate our fiscal discipline by securing contracts that are in full simple payback on the reactivation CapEx we are investing.
And finally, we are building contractual backlog and we have substantially improved our liquidity and balance sheet and expect meaningful improvements and leverage ratios and other debt metrics as we move through 2023 and beyond.
So summing all of this up, ICD checks all the boxes, whether you’re looking for best-in-class assets, leading rig margins, or an outstanding customer base and rigs focused on the most important oil and gas shale plays in U.S. unconventional, ICD delivers on those metrics.
With all this in place or operations are closing any historical financial gap between us and our larger public company peers. And we believe all these efforts and results will work toward closing the stock valuation gap between ICD and our peers as we continue to execute upon ICD strategic initiatives.
With that operator, let’s go ahead and open up the line for questions.
Question-and-Answer Session
Operator
Thank you. We will now begin the question and answer session. [Operator Instructions] And the first question will come from Don Crist with Johnson Rice. Please go ahead.
Don Crist
Morning, gentlemen. How are y’all today?
Philip Choyce
Good, Don. How are you?
Anthony Gallegos
Doing great, Don.
Don Crist
I wanted to touch on slide 21 of your presentation with revenue per day and contracted backlog and just ask, I know there’s differences between rigs and operators and contract from Series 2 to Series 300 rigs. And I wanted to know, is the numbers for 2023, are those representative of average numbers? Or is that just the couple of rigs that you have contracted today? And what would that delta be? Would it be 10% less on an average across your entire fleet or something like that?
Philip Choyce
Yes. So in that presentation, what’s in that backlog is going to be a mix of rigs throughout the quarters. And obviously towards the end, the fourth quarter, there’s not that many rigs in the backlog. There’s a mix of 300 Series and 200 Series rigs in there, and a couple of them our contracts on our rig reactivations, we’re putting out the 19th and the 20th rigs that we have contracted. The delta between a 200 Series rig and a 300 Series rig is probably $2,500 a day. It could be a little less, could be a little more depending on the application and the customer. But we are seeing for the 300 Series rigs at the high end, day rates, and the high 30s and we have — we do have — revenue per day could be — for a particular contract could be over $40,000 a day with that or it’s not quite that high for on the high end for a 200 Series rig, but again, it’s going to be a couple $1,000 stable
Don Crist
Okay. So just looking at the kind of modeling purposes that these are good numbers for kind of an average across your fleet. Is that correct to what you say?
Philip Choyce
That wouldn’t be — I would say, its more towards the 300 Series certainly on the higher day rates.
Don Crist
Okay. Sorry, go ahead.
Philip Choyce
Yes. From a day rate perspective, we’re going to get — there’s going to be a mix of rigs, leading edge, or what I just talked about, but not every rig is going to get a leading edge, because not every customer requires the same type of equipment as different customers have different drilling programs.
Don Crist
Right. Okay. And as far as the 200 Series upgrades, obviously, last quarter, you talked about a couple of them in the pipeline. Where do we stand on that? And obviously, you’re doing your first one now, but how many more in the pipeline? And what’s the interest level there to complete a majority of your 200 to 300 Series upgrades?
Anthony Gallegos
Yes. Don, the first one, as we noted is underway, will be completed, by the end of the week. We are doing that in the field, so rig move, that’s a little longer than normal. Obviously, customers on board with that. So that one will be complete. We talked about doing a couple of them by the end of the year, timing on the second, the third is kind of slipped into 2023. And that’s really being driven more by the customers requirement than anything else. In terms of converting all of the fleet, we’ve never said that, we’re going to do that. I don’t know that we’ll have to do that. We’re only going to do it where there’s an opportunity there for us to invest in incremental CapEx and our return on that incremental CapEx.
So, really pleased with what we’ve been able to do with our 200 series rigs. Notwithstanding the upgrades, rigs continue to perform very good. Day rates on those continue to move up like they are with the rest of our fleet. So, we look at that 200 to 300 series conversion of that class of rig is really something more optimistic for the company. And we do have a couple of kits on the ground, so that when our marketing team is talking to current customers and prospective customers, it’s something that we can execute on very easily and very quickly. That’s how we’re thinking about them.
Don Crist
Okay. And just one final one for me. Obviously, you’ve started the term up a little bit of your fleet here versus mid part of 2022, as you take advantage of pricing. What is the optimal level there is? Do you want to get to 40% or 50% of your fleet contracted with one plus year term backlog? Or what’s your thoughts around that?
Philip Choyce
Yes. So, obviously, we want to think about where we are in the cycle. Certainly, the free cash flow generating opportunities that are available will factor into that decision as well. So, what we’ve said, and how we think about it is just looking at it from a portfolio perspective. Where we see longer — better opportunities, maybe for the bigger rigs, maybe don’t go quite as long on those if you’re not investing incremental CapEx. Whereas the other part of the fleet, you might put a bit more term on the books around those. But I would expect as we roll into 2023, especially as our customers begin to announce what their plans are, that’s going to provide us ample opportunities to look and try to find that optimal amount of backlog relative to the available days that we’ll have in 2023. So it’s not a hard and fast number. I would expect us to continue to add some backlog, but not look to commit everything that we have. We just think there’s more upside from where we are today, Don.
Don Crist
I appreciate all the color. I’ll get back in queue.
Anthony Gallegos
Yes. Thank you.
Operator
Thank you. And the next question comes from Steve Ferazani with Sidoti. Please go ahead.
Steve Ferazani
Good morning, folks. Appreciate all the color on the call. Wanted to get a sense if you’re seeing any shifts in demand. Are there any particular strong pockets? Sounds like the two rigs you’re sending out, the most recent rigs that are coming out are coming into the Haynesville? And any diversification in demand and any areas you’d be more targeting?
Philip Choyce
We’ve been really pleased with the way our geographic markets have played out over the year, obviously very, very excited, Steve about what’s happening in the Haynesville. We were able to grow, for example, our market share in the Haynesville over the third quarter. And we currently represent about 14% of the market share over there compared to about 3% in the Permian. So, we talked in prior calls about how — in the Haynesville, we want to view the requirements over there, not just from a technical standpoint, but especially from an operational standpoint or higher. It allows us to exploit the competitive advantage that we have relative to some other contractors, and continue to build on that presence over there. So, obviously, gas prices have moved up over this year, things have been a little bit more flat here over the last couple of months. But, a lot of optimism in the industry, certainly a lot of optimism within ICD, about where the gas markets going over the coming years. And I’m very, very excited that we can play a part in that.
Steve Ferazani
Are there any — Haynesville versus Permian are there — are customers more likely to want term in one or the other, or is it no difference?
Philip Choyce
No, I think our opportunities to push term maybe a little better in the Haynesville and it gets back to just the number of players in that market. It’s not quite as fragmented as it is in the Permian, for example, the technical requirements and like I said, certainly the operational requirements are a little bit higher. So, frankly, that is probably where we put more backlog. The term on the books is in the Haynesville market compared to the Permian. So yes, I would acknowledge that there is an advantage in that respect for us in the Haynesville today.
Steve Ferazani
Great. As you’re rolling out these rigs, I’m assuming you’re adding roughly 20, 25 people per rig you’re adding, How challenging is that becoming? And how do you mix the crews up as you’re having to add to your two crew sizes?
Philip Choyce
Yes, your numbers are spot on. It’s 22 to 25 people per rig coming out. And a lot of risk associated with starting up new rigs, and the way that we manage it, is you’re going to hire 22 to 25 people, but you don’t put them on that rig coming out, they get dispersed within our fleet, or operating fleet, and we bring 22 people from existing rigs, people that had been with us a while that understand and know our systems and processes that bought into our culture. In terms of how hard has it been, we’ve not had a problem attracting talent, and bringing them in the company. The challenge that I think all of us have had is around retention and retaining those people. And the problem really is and the challenge really has been at that lowest level that entry level within the company. You’re dealing with somebody that is going to be very young, most likely first time to have a job, especially one is demanding as our entry level positions are.
And we continue to try to be very creative in finding ways to enhance that retention, because it’s not just $1 impact. There’s impacts to safety, impacts to efficiency, productivity, client satisfaction, and all of those things. So, to answer your question, as we have continued to bring rigs out, we have been able to find that talent and continue to be very, very focused in the company on what we call people development, which is making sure that we have talent that’s ready to step up and take that next position.
Steve Ferazani
Thanks, Anthony. Thanks, Phil. Appreciate the time.
Philip Choyce
Thank you, Steve.
Operator
The next question will be from Jeff Robertson from Water Tower Research. Please go ahead.
Jeff Robertson
Thank you. Good morning, Anthony and Phillip. Anthony talked about rig. You talked about reactivating rigs 2023 and 2024, middle part of next year. And you also mentioned,
decisions around how long you want to PIK interest on the note, just given where rates are. Can you talk a little bit more about the specifics of what your thought process is around continuing to PIK interest through I believe it’s the first quarter of 2024 and how that plays into your capital assumptions for the incremental reactivations?
Anthony Gallegos
I’ll give you my views, and then I’ll let Philip chime in as well. But look, we — Jeff, we’ve said all along, we want to be very, very deliberate in making capital investment decisions. When big difference in oilfield services and certainly ICD today versus prior cycles is we don’t want to grow just simply to grow. Its undeniable that we live in a world and live in times with tremendous uncertainty. Very proud and pleased that we’re going to meet our goal of ending this year with 20 rigs operating, another couple in the pipeline that are going to come out in the first quarter, and where margins are today with 20 to 22 rigs running, we believe that it will give us the scale to achieve the longer term goals as we’re thinking about where we want to take the company. You do have to be mindful of where CapEx is today on incremental startups. Look, we’re going to be spending $8 million plus on rigs in this kind of time period. Our debt as you know, has variable rate interest on it. So as interest rates have moved up, that service cost is going up as well. So that’s kind of how I’m thinking about it. And Philip, do you want to add anything?
Philip Choyce
Yes. So the PIK interest feature does two things for us. It gives us capital to reactivate rigs right now. But the other important piece of it, it’s allowing us to improve our working capital position. We do have some goals there to add cash to our balance sheet and to remove all that. We do have some debt borrowed on our on a revolver. So, if we can get to $15 million, $20 million cash and no revolver debt, that’s kind of where we’d like to have the company. And we think about an opportunity if we could — if we — if there’s an opportunity to push a rig that we may put out in the middle of a summer to the fall, where actually that’s a better marketing windows, because it’s closer to our budget, our customers budgeting season. And we can remove, for example, that last PIK interest payment, because the way we think about that PIK interest, if we’re putting out a rig and we’re picking interest, that interest component is a capital cost of that rig. And so we’re looking at that as part of our return analysis as well. So that would be the reason or how we think about it.
Jeff Robertson
Just a follow up on slide 26, where you talk about the potential debt reduction, and really the potential improvement in the leverage ratio. Phillip, is there a point in time where or a leverage ratio target where you think the company could take advantage of to consider some sort of capital market alternative to refinance the convertible notes into something more conventional?
Philip Choyce
Yes. So the convertible notes has the kind of defeasance period begins 18 months prior to maturity. So that’s going to be an early 2015 [Indiscernible]. So doing it earlier is more expensive than doing it later. That would be the window where we can look at refinancing alternatives. And that’s really what we’re trying to do is and I think Anthony mentioned, we want at that point in time in that window to have our debt to — net debt to EBITDA ratio as low as possible. So, and we can either refinance the notes and pay them off in their entirety with free cash flow, or if there’s a portion we need to refinance, we’re going to do that on a regular way, refinancing. And if you look at where we’re going, and that slide you’re talking about right there, we’re not — we’re assuming the margins that are consistent with what our first quarter guidance is. And so we feel very good about our ability to do that in a market that we think is going to be constructive during this period of time.
Jeff Robertson
Yes. The cash balance that you’re showing growing should be a big benefit as you think about the options with those notes. I would like to thank you for taking my questions this morning.
Philip Choyce
Thank you, Jeff.
Operator
Thank you. And the next question will be from Dave Storms from Stonegate. Please go ahead.
Dave Storms
Good morning, gentlemen, and thanks for taking my call. Just want to circle back on Don’s question with regards to contract lengths. Are you currently happy with the length of the contracts? Or if rates begin to rise should we expect to see contract lengths that would expand even further?
Anthony Gallegos
Dave, starting to layer on some six month and one year contracts, I will tell you we’re in discussions right now on an 18 month contract as well. So yes, I believe that the demand — the incremental demand that’s coming into the market around 2023 programs is going to create so much competition for super-spec, pad-optimal rigs that there will be opportunities to contract rig for longer than one year. And certainly in that environment, you would expect to see day rates continue to move up. And in that environment, I would expect us to take advantage of those opportunities and put even more backlog on the books. Again, not contracting everything. I think, we want the exposure. We want the torque that the pad-to-pad contracts we’re going to provide. But certainly these kinds of economics, I would expect us to take advantage of that.
Philip Choyce
And Dave, I think the other thing is to think about not just us, but the industry, the reactivating — the rigs that are reactivating are getting more expensive. There’s inflation, there’s supply chain constraints and things like that. So as you look at the cost to reactivate rigs and what ICD or even one of our competitors are going to need to reactivate those rigs, you’re probably going to see rates need to improve. And you’re going to possibly see contract tenders go out. Because you’re looking at not only — you want contractual payback of those reinvestments, but you want to ensure your returns as well.
Dave Storms
So, are you seeing any pushback from customers when you go to negotiate some of these contracts? Or do they see it in their best interest as well to lock in these rates? And it’s kind of a win-win, where you’re also able to essentially defeat some of the costs for reactivating some of these rigs?
Anthony Gallegos
Yes. I don’t know that I would phrase it as pushback, there’s — we’re at historical levels in terms of day rates in U.S. land, they maybe not sticker shock, probably not the right word. But clearly as 2022 is played out, we’ve been optimistic that day rates will continue to increase. There are some E&Ps that believe they — maybe they’ve reached a ceiling. But no, we’re very optimistic that day rates will continue to go up. You think about the types of capital investments that are being made, if you’ve listened to any of our competitors, talk about maintenance CapEx, for example, that number continues to go up as well.
And look, at the end of the day, we have to earn returns in excess of our cost of capital. And when you look at the current economics around this today, maybe we’re treading water in that regard. But we have to generate returns in excess of our cost of capital, or which is drawing value. So I believe that, it’s another big difference in oilfield services today, compared to prior cycles is that I believe we’re all thinking about things in this way. And all that tells me that day rates will continue to increase for no other reason, just from an economic necessity standpoint.
Dave Storms
That’s perfect. Thank you.
Anthony Gallegos
Thank you, Dave.
Operator
[Operator Instructions] The next question is from David Marsh from Singular Research. Please go ahead.
David Marsh
Hey, guys. Thanks for taking the questions. Just quickly on the on the convert, is there any kind of feature in the convertible note that would allow you guys to press conversion of it if the stock closes above the strike price for a certain number of days? Is that something you guys would consider at all?
Philip Choyce
As it’s drafted now, the conversion is not — there’s not a mandatory convert feature in there like that. So it’s the conversions at the option of the holder.
David Marsh
Got it. And just doing some quick math, I’m getting about 37.7 million shares at the current par value if it were fully converted, is that the right number?
Philip Choyce
It’d be 170.1 million divided by 451. So, whatever that number is. Like your background? Yes.
David Marsh
Okay. Beyond that, I know it’s probably still a little bit in the planning stages. Do you guys have a CapEx budget for 2023 yet?
Philip Choyce
No, we’re just starting to work on that now. The two big variables will be, ultimately, what is our maintenance CapEx on a per operating rig basis, but also, how many incremental rigs are we going to bring out for 2023. So we have started that process. We are working on it now. But it’s a bit early to give you guys any guidance today.
David Marsh
Sure. Completely understand. And lastly, when you look kind of across the industry, I mean, obviously, we have a pretty strong idea of your utilization and where you’re going. Where do you think the industry is kind of globally in here in the U.S. with regards to utilization?
Philip Choyce
I think it’s very high. And the reason I say that is if you look at where demand is coming from today in the United States, it’s in the U.S. unconventional plays. And within those plays, in order to be effective, you have to have what we call a super-spec, pad-optimal rig. When you — best we can tell when you look at that market today, their utilization is well above 90%. Another key difference today, compared to prior cycles is most of that capacity is controlled by just a handful of companies. And where I get really excited is, when people talk about what 2023 will look like? I think the consensus is there’s — obviously, there’s going to be more demand for rigs.
There’s numbers out there ranging from 50 to 100 incremental rigs over the next 12 months. But what gets me really excited is when you look at where is that incremental supply going to come from, there’s only four or five companies out there. ICD is one that has some capacity that can come out at something that’s reasonable in terms of economics. But half of that incremental supply of super-spec rigs is held by one guy, one company. And it’s 48% of it. And that guy just came out and said, he’s only going to bring out 16 rigs in the next 12 months. So this is something that’s probably under appreciated by people. But I think it speaks to how strong the market is today and how strong we believe it’s going to be in 2023. So obviously, we’re very excited for all of those reasons.
David Marsh
Thanks, guys. That’s great insight. Really appreciate it. Thank you.
Anthony Gallegos
Thank you, Dave.
Operator
The next question is a follow up question from Don Crist from Johnson Rice. Please go ahead.
Don Crist
Thanks for letting me back in guys. I just wanted to ask about the supply chain and more specifically drill pipe, because one of the major suppliers reported a couple of days ago and said that there was some weakness in their growing backlog for 5.5-inch drill pipe. Can you just talk about that market and just overall supply chain? And kind of where you see it trending into the first half of 2023?
Philip Choyce
So, we don’t — there are some drilling contractors that actually buy and rent their 5.5 inch drill pipe with their rigs. We’re not — we don’t do that. That’s not included in our day rates and things like that. So we’re not buying that type of drill pipe. We’re typically buying 5-inch pipe when we buy it. You’re looking at six to nine months. So what we’re seeing delivery times. And so that’s really what you’re looking for there. Its pushed out a little bit. But it’s manageable, but it is pushing out.
Don Crist
And what about the other components for just the reactivation is. Is it getting better or worse, or about the same as it’s been over the last call it six months or so?
Philip Choyce
I think its pushed out a little bit. If we talk six months ago, when we’re talking about reactivating one of our rigs, we’re not really buying a lot of brand new equipment. We’re overhauling engines, top drive, mud pumps that haven’t been used for a while. And just like other contractors, the first rigs that went out, we put them out with the pumps and engines and top drives that were the easiest to put out. And now we’re kind of all at the end of our inventory. So it’s really a lot of maintenance CapEx and a lot of ways that we’re having to spend [ph] on the front end. And just like everyone is supply constrained, a lot of those shops are also supply constrained. So we’ve got to get into queue sooner rather than later. And so, that’s why we’ve brought forward some of like, in particular, the March rig, we’ve already ordered a lot of items for that rig, just because we needed to keep it in the queue. And we’ll be doing the same thing on the 23rd and 24th rigs as well. So that pushed out a lot. It’s not 12 months, but there’s things we’re having to order six or seven months before rigs going to be reactivated.
Don Crist
I appreciate the color. Thanks.
Operator
Ladies and gentlemen, this concludes our question and answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks.
Anthony Gallegos
All right. Thank you. I just want to be brief here and thank everyone for their time and dialing in this morning and participating in our call. And I want to wish you all a safe and productive day. Thank you.
Operator
Thank you, sir. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
Be the first to comment