Independence Contract Drilling, Inc. (NYSE:ICD) Q2 2022 Results Conference Call August 4, 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
Jeff Robertson – Water Tower Research
Operator
Good day, and welcome to the Independence Contract Drilling Second Quarter 2022 Financial Results and Conference Call. [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, Executive Vice President and Chief Financial Officer. Please go ahead.
Philip Choyce
Good morning, everyone, and thank you for joining us today to discuss ICD’s second 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.
With that, I’ll turn it over to Anthony for opening remarks.
Anthony Gallegos
Hello, everyone. Today, I have several exciting opportunities to discuss starting with how our 200 to 300 series conversions and related increase in our marketed fleet will significantly enhance ICD’s strategic positioning within the U.S. land rig market. I also want to highlight our view that the U.S. land rig market continues to be very tight with increasing dayrates and utilization momentum.
I want to leave you with these 3 focus points for why ICD is ideally positioned to take advantage of this tight market and generate significant returns for all of our stakeholders. First, as forecasted to you, ICD’s margin per day EBITDA progression in the first half of 2022 has been substantial. During the pandemic recovery, our priority for ICD has been to rapidly close the margin gap between us and our larger public company peers. Both our utilization and margin acceleration off the COVID bottom has been the fastest in the industry, and there’s more to come.
In the second quarter, our margin per day increased sequentially by 56%, and we expect margins will continue to expand significantly through the remainder of this year and into 2023. We are finally starting to realize the results of strategic planning and initiatives that began several years ago, which were put on hold as a result of the COVID pandemic.
The second theme of my comments today is our announcement relating to our 200 to 300 series conversion program and increase in our marketed fleet to 26 rigs. This initiative has important strategic ramifications for ICD, not only from a margin generation point of view, but also with respect to ICD’s market positioning moving forward given our belief we are still in the early innings of a multiyear up cycle for U.S. land.
And finally, I want to emphasize how extremely tight super-spec rig supply is today, especially in ICD’s target markets, and a very exciting opportunity in front of ICD to reactivate rigs into this market and into our evolving and expanding customer base.
Now just a few comments on the quarter. We reported revenue per day of $24,875 and margin per day of $8,946. This represented a 14% sequential increase in revenue per day, and as I just mentioned, a 56% increase in margin per day compared to the first quarter of 2022, exceeding the guidance we provided during our last quarterly earnings call.
Overall, we reported adjusted EBITDA of $9.2 million, representing a 158% sequential increase from the prior quarter and also higher than prior quarter’s guidance. Over the last 12 months, our reported margin per day have expanded 183%, the highest growth percentage among public U.S. land drillers.
So what is driving this margin acceleration? Because we are not as big, and we don’t offer all the ancillary services or include rental drill pipe in our margins as many of our larger competitors do. I’ll get to this more in a moment, but it comes from an intense focus on client satisfaction driven by safe and efficient operations and the continued penetration of our 300 series rigs, improved marketing strategies and execution and our reputation and awards for industry-leading service and professionalism within our target markets. I also believe our geographic focus and, in particular, our underappreciated presence in the Haynesville contributes favorably.
Most importantly, market conditions and demand for our pad-optimal, super-spec rigs continue to improve rapidly. So I’m quite optimistic about continued meaningful sequential margin improvements in the upcoming quarters. For the third quarter, we’re forecasting approximately 14% sequential increases in margin per day. And based on the contracts we have in place today and a significant number of ICD rigs that will rerate again throughout the fourth quarter and into 2023, meaningful sequential margin progression should continue. Thus, combined with the incremental 300 series rigs we will add over the next couple of quarters, we expect robust sequential growth in adjusted EBITDA to continue into 2023.
While our strategy, thus far, in this recovery has been on securing shorter-term pad-to-pad contracts as dayrates have continued to strengthen, in particular for our 300 series rigs, where spot rates are now firmly in the low to mid-30s depending on contract [daters], we have begun evaluating and, in some cases, signing some longer-term contracts. For example, our 18th rig which just mobilized is on a 1-year term contract in the Haynesville, and we recently signed another 1-year contract and a few 6 months contracts.
Overall, we remain very constructive on further dayrate improvements but believe current economics and the ever-present cyclicality of our industry now warrants some backlog and probably makes sense as we enter our customers’ 2023 budgeting season, and we look at reactivate additional activate rigs.
I think it’s also worthwhile at this point to mention our evolving customer mix, which I think also contributes to our improving financial performance and overall market positioning. As we sit here today, we have 18 rigs operating: 7 are working in the Haynesville; 10 are working in the Permian; and 1 is working on the Gulf Coast on a carbon capture project for a super major E&P. Over the past quarter or so, we’ve added several key large independent public clients to our customer base who we believe are ideal candidates for additional rig adds as we enter the 2023 budgeting cycle.
Today, 7 of our rigs are working for public E&P operators and 7 of our rigs are operating for the 2 largest private operators in the Permian and the Haynesville. Overall, that’s almost 80% of our operating fleet. I think this is an underappreciated fact regarding ICD. When I would stack up against any of our competitors, which is being driven not only by our superior rig plate, but by the ICD team’s reputation for service and professionalism in our target markets.
When I look forward, I believe we are still in the early innings of the most constructive market for pad-optimal, super-spec rigs we’ve ever seen. At this point, I feel it’s safe to say that for the most part, the COVID hangover for ICD is over. And what we’re seeing now in ICD’s improving margins, enhanced customer base and rig utilization is early manifestation of the benefits from strategic decisions we made as far back as late 2018 when we consummated the merger with Sidewinder and began the integration of the 2 rig fleets and leveraging the merged customer base.
I’ve spoken about this before, but I think it’s a good time to revisit the question. What is different about ICD now compared to when we entered the pandemic? Why is ICD’s utilization, dayrate and margin progression outpacing our larger public company competitors? As we’ve highlighted on past conference calls, we’ve been focusing more on shorter-term contracts in what we believe are the early stages of this up cycle. Backlog is important. And as I’ve mentioned, we are looking to increase that as we move into the 2023 budgeting season, and rigs such as our 300 series rigs earned $15,000 per day margins are higher.
Where there are opportunities for term contracts and building our backlog, especially with target customers at appropriate rates and margins, we will look to execute upon those. I’m not signaling that we wish to term up everything, just that we want to take a balanced portfolio approach in our contracting strategy as we continue to expand ICD’s operating rig fleet and earnings capability.
Most importantly, ICD’s operating fleet mix is different and how we are marketing our fleet to maximize margins and returns is different. We believe our 300 series rigs are an underappreciated value proposition embedded in ICD’s fleet. We acquired all 14 of our current 300 series rigs in our merger with Sidewinder in late 2018, and this current up cycle is the first time we’ve been able to market these rigs across ICD’s expanded customer base and consolidated target markets in an improving market.
For reference, we had an average of 3 300 series rigs operating in March 2020 prepandemic. Today, we have 8 operating and we’ll have 10 running by the end of 2022 with additional 300 series rigs available for reactivation in 2023. So we have fundamentally changed our fleet operating mix.
Rigs meeting 300 series specifications are in the shortest supply, and they command premium dayrates. In fact, today, spot market dayrates for this class of rig start with a 3, and with adders can easily reach the mid-30s or higher. Not every operator requires rigs with 300 series specifications. But as acreage positions become more contiguous, pads get larger, laterals get longer and wells get deeper and more complex, demand for rigs with these 300 series specifications continues to grow. And as we’ve been intentionally patient about how we market and reactivate these rigs, not just reactivating them for the sake of reactivating, but making sure we don’t outrun our organization’s capability while placing these rigs with customers who need their performance characteristics in order to secure these higher margin generating opportunities.
And what is abundantly clear over the past 12 months is this: as these rigs in our operating fleet, our margin projection accelerates and they are a significant reason why our overall fleet margins today are largely on par with our larger public company peers and rapidly improving, something we could not say prepandemic or even premerger 2018. I also believe these rigs enhance our competitiveness in the Haynesville and Delaware basins, which has been an important driver for our evolving geographic mix and improvements in our customer base with respect to larger operators in these plays.
All this leads me to why I’m so excited about our announcement today regarding our 200 to 300 series rig conversions. This is something we’ve been working on since — prior to the pandemic, making sure the engineering is right, capital costs are identified so that this opportunity makes strategic, operational and financial sense. And I couldn’t be more excited about what has been accomplished in this regard.
So what does all this mean for ICD’s fleet capabilities? Simply, it means almost all of our marketed fleet can now be marketed with 300 series specifications. Again, rigs with these specifications are in the highest dayrates and highest margins and are in the shortest supply.
Prior to this announcement, we had 32 total rigs, of which 24 were included in our marketed fleet. Of these 24 marketed rigs, 14 met the 300 series specification. That’s approximately 60% of our marketed fleet. With all of the engineering and operational plans in place for these 200 to 300 series conversions, we have now increased our marketed fleet to 26 rigs, of which 25 can now be marketed with 300 series specifications.
In other words, we’ve increased the 300 series component of our marketed fleet to 96%, up from 60%. And when you consider what we’ve been able to accomplish so far with margin progression, the ability to convert 200 series rigs in our operating fleet to 300 series specifications will only accelerate margin expansion and our comparative competitive posture with respect to our larger public company peers.
In addition to our 18 operating rigs, we now have 8 additional rigs, all 300 series rigs, that can be reactivated as market conditions warrant. And based upon current rates and estimated reactivation costs, we expect to earn 1 year of better paybacks on these reactivation investments.
Regarding the 200 to 300 series conversion opportunities, it’s important to note, we currently have contracts just signed to convert 2 of our operating 200 series rigs to 300 series specifications. These conversions will occur late Q3, in early Q4, and we are negotiating a third conversion commitment that would occur here during 2022. CapEx costs to affect these conversions is minimal, especially compared to the significant strategic consequences of these actions. We expect each conversion to cost approximately $650,000.
In addition, we can execute the conversions on a long rig move, only a handful of days, so there is minimal operational downtime. And based upon current dayrate differentials between 200 and 300 series spot market rates, we expect these conversion investments to pay back in less than a year.
However, similar to how we’ve been careful in marketing our 300 series rigs to customers who will value and pay for these rigs’ additional capabilities, we will do the same when considering additional conversions of existing 200 series rigs to 300 series specifications. When customers require it and are willing to compensate us for the capital investments and added performance characteristics, we will make the conversions.
In the meantime, our 200 series super-spec rigs remain in very high demand, and they are also earning substantial margins that continue to increase. So we’re in a very enviable position with a very young, flexible, rig fleet capable of satisfying all of our customers’ drilling requirements, whatever their rig needs be.
Spoken about the tightness in the super-spec market in the past, and that tightness continues, and this is particularly exciting for ICD when you consider, not only our current 18 rig operating fleet, but the additional 8 rigs we have available for reactivation. Again, all 300 series rigs. The market for pad-optimal, super-spec rigs, such as our ShaleDriller fleet is as tight as I’ve ever seen and, in particular, for our 300 series rigs. For the most part, there are no hot super-spec, pad-optimal rigs available today. If an E&P operator wants an incremental super-spec rig, it will likely have to come out of stack, and reactivation costs for all drilling contractors today are very significant.
And another thing I believe may be underappreciated, not only is there very limited supply of incremental pad-optimal rigs that must come out of stack, but because most contractors are sold out. There’s only a small number of contract drillers an operator could go to if they want an incremental super-spec rig. ICD is fortunate to be one of them. This is the market dynamic, which we are marketing our 8 incremental 300 series rigs into and why we are so excited about these opportunities and what they mean for our company, our customers and our stockholders.
The market needs more pad-optimal, super-spec rigs, in particular rigs meeting 300 series specifications. And we expect the U.S. land rig count, in particular in our target basis, will continue to increase. This demand, coupled by industry capital discipline, is driving dayrates and margins higher at a pace not seen before. Today’s spot market dayrates for 300 series rigs are above $30,000 and with adders approach mid-$30,000 or even higher. And rigs meeting 200 series specifications aren’t far behind.
So as I close out this portion of my prepared remarks, I want to reiterate that it’s not just our dayrate margins that are improving. Performance of our rigs remains strong, whether the metric is safety, downtime, rig move times or days to depth, and that is reflected in our evolving customer mix. I want to thank our sales and marketing team for their hard work in making sure that we have very attractive contracting opportunities.
I also could not be prouder of how our operational teams and field and support personnel have responded to the challenges before them, whether it’s the unprecedented tight labor market, supply chain challenges and disruptions that persist or all that they do to safely and effectively reactivate rigs and manage and exceed our customers’ increasing and evolving performance expectations.
I think we sometimes get distracted talking so much about our equipment performance that we don’t highlight ICD’s focus on our people and culture. In reality, it is the ICD people and our culture that make the difference. It is our dedicated employees who get the rigs out safely, on time, on budget and with minimal downtime and operational disruption. They are in the accolades our company has received for industry-leading service and professionalism and why our premier customer list and margins continue to expand.
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 more detail.
Philip Choyce
Thanks, Anthony. During the quarter, we reported an adjusted net loss of $9.8 million or $0.72 per share and adjusted EBITDA of $9.2 million. We operated 16.9 average rigs during the quarter. We expect to operate approximately 17.5 average rigs during the third quarter based upon our 18th rig commencing operations around August 1. Our 19th and 20th rigs are not scheduled to enter our operating fleet until the fourth quarter.
Revenue per day came in at $24,875, representing a 14% sequential increase over the first quarter. Cost per day of $15,929 were favorable compared to prior quarter guidance. Cost per day does reflect upward field pay adjustments we implemented June 1 of this year, which will be fully reflected in the third quarter and onward. That’s about $550 per day. Overall, margins came in at $8,946, representing a 56% sequential increase and ahead of guidance provided on our prior conference call.
SG&A costs were $4.9 million, which included approximately $670,000 of stock-based and deferred compensation expense. Cash SG&A was relatively flat compared to the first quarter, while stock-based compensation was favorable based upon variable accounting and stock price declines quarter-on-quarter. Interest expense during the quarter aggregated $8.2 million. This included $2 million associated with noncash amortization and deferred issuance costs and debt discount, and we excluded that when presenting our adjusted net income.
The PIK interest rate used during the quarter was SOFR plus 14%. The new rate of SOFR plus 9.5% on a convertible note becomes effective at the end of the third quarter of this year. As mentioned on our prior calls, we do expect the PIK interest while we continue to reactivate rigs, which we expect to continue at least through next year assuming market conditions remain strong.
We did recognize a sizable tax expense during the quarter of approximately $0.16 per share. We are now forecasting book income for the year after adding back permanent differences, which largely relate to interest expense and noncash charges. This change generated the large expense during the quarter, and I do want to point out that only $300,000 of this recorded expense relates to cash taxes for state and local matters. For federal income tax purposes, we maintained substantial future depreciable assets as well as a sizable net operating loss position.
During the quarter, cash payments for capital expenditures net of disposals were approximately $4.5 million. Breaking this CapEx out, approximately 37% related to rig reactivations, 47% related to maintenance CapEx and 16% related to investments in capital inventory and spares. There’s approximately $5.6 million of CapEx accrued at quarter end, which we expect will flow through during the third quarter of 2022.
Reactivation plan for our 19th and 20 rigs remain on schedule, and we have begun ordering long lead time items relating to our 21st rig, which is planned for January 2023. And as Anthony mentioned, we plan to complete 3 200 to 300 series conversions during the second half of this year at an aggregate cost of approximately $2 million. With these changes, we have increased our CapEx budget for the year by $4.5 million to $28.5 million.
As Anthony mentioned, we have begun entertaining longer-term contracts. As a result, our backlog is beginning to increase. However, most of our rigs are operating on short-term contracts and will reprice 1 to 2x during the remainder of the year. Our backlog of term contracts with original terms of at least 6 months as of June 30 stood at $54.3 million. Approximately 36% of the backlog extends into 2023 at an average dayrate of over $32,000 per day.
Moving on to our balance sheet. I want to point out that we’ve included in our press release a new measurement, adjusted net debt. This amount represents the face amount of our convertible notes and borrowings under ABL, less cash and ignores impact from debt discount, deferred financing costs and finance leases. I also want to point out that the derivative liability reflected on our March 31 balance sheet was reclassified to additional paid-in capital and gain on extinguishment of derivative this quarter. This was triggered by the shareholder vote at our Annual Meeting in June, which eliminated potential variabilities in the conversion price and PIK interest rates under the convertible notes.
The note conversion price is now set at $4.51 per share. And as I already mentioned, the PIK interest rate under our notes will drop the SOFR plus 9.5% beginning September 30. Prior to that time, the PIK interest rate remains at SOFR plus 14%.
At quarter end, we reported adjusted net debt of $158 million. This adjusted debt was comprised of the convertible notes and $7.8 million drawn on our revolver, and finance leases reflected on our balance sheet at quarter end were approximately $4.8 million. And we did not issue any shares under our ATM program during the quarter. At quarter end, our financial liquidity was $21.3 million, comprised of $7.3 million of cash on hand and $14 million available under our revolving credit facility.
Now moving on to the third quarter guidance. We expect operating days to approximate 1,610 days, representing 17.5 average rigs working during the quarter. We expect margin per day to come in between $10,100 and $10,400 per day, representing an approximate 14% sequential increase at the midpoint of this range. We expect revenue per day to come in between $27,350 and $27,550 per day with many of the dayrate increases on contract rolls only partially benefiting the third quarter. Cost per day is expected to range between $16,800 and $17,200 per day, sequentially higher as pay adjustments implemented in June fully impact the third quarter and we incur operating costs associated with reactivating our 18th and 19th rigs.
Based on contracts in hand and assuming spot market pricing and operating costs remain stable, right now, we would expect fourth quarter margins to come in between $11,500 and $12,000 per day. Unabsorbed overhead costs will be about $600,000 and they’re also included in — are not included in our cost per day guidance. We expect third quarter cash SG&A expense to be approximately $4.6 million with sequential increases tied to higher incentive compensation accruals. Stock-based compensation expense is expected to be approximately $900,000 with a sequential increase being driven by annual awards that became effective following our annual meeting in June of this year.
Interest expense to be approximately $8.6 million. Of this amount, approximately $2.2 million will relate to noncash amortization of deferred financing costs and debt discounts. Depreciation expense for the third quarter is expected to be approximately $10 million. We expect tax expense during the third quarter to be approximately $400,000. For capital expenditures, we expect approximately $6.5 million net of dispositions to flow through our cash flow statement during the third quarter.
And 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 make a couple of comments regarding ICD’s strategic positioning and what I think it means for all ICD stakeholders. We forecasted this evolution during prior calls. So much has changed for ICD over the last 4 or 5 months. And I think it’s important to focus on how much we have truly transformed our company and the opportunities for our investors and other stakeholders.
Our utilization and margin growth coming out of the pandemic is best-in-class. Our contracted rig count has increased by 500% compared to an increase in the U.S. land rig count of approximately 200%. And over the last 12 months, our margin per day has expanded to 183%. And as I’ve highlighted in my prepared remarks, there’s more utilization and margin growth to come. We have the youngest and we believe the best-in-class rig fleet with our announcement today that will allow us to market 96% of our fleet with 300 series specifications. We firmly believe the capabilities of our fleet are best-in-class.
Our customer list is expanding and evolving in meaningful ways, and we’re operating not only in the most important oil and gas plays in North America, but for what we believe are the most important customers in these target markets, many with an eye toward expanding their rig count in the coming quarters. We are marketing incremental 300 series rigs in one of the tightest rig markets we’ve ever seen, and ICD is one of only a few contractors with visible spare 300 series capacity that can be economically reactivated. Finally, we’ve substantially improved our liquidity and balance sheet with the refinancing we announced earlier this year.
To sum it all up, I think we are checking all the boxes, whether you’re looking for best-in-class assets, leading margins, leading customer base, focus on the most important oil and gas plays, financial or operational upside or leading industry reputation, ICD delivers on all those metrics. With all this in place, our operations and financial performance is closing any gap between us and our larger public company peers, and we believe all of these results will work toward closing the stock valuation gap between ICD and our peers as we continue to execute upon ICD strategic initiatives.
So with that, operator, let’s go ahead and open up the line for questions.
Question-and-Answer Session
Operator
[Operator Instructions] The first question today comes from Don Crist with Johnson Rice.
Don Crist
Anthony, I really applaud the engineering and the somewhat ease in what your — you’ve outlined going from a series 200 to 300 rig and the speed in which you seem to be able to do it as well. So my question is when you’re having conversations with the customers that have the 200 series rigs today, are they in the market for a 300 series and they are only able to get a 200 series? And are they showing significant interest in going through that upgrade process on a long rig move? And the second part to that question would be, what is the dayrate difference between a series 200 that you’re charging today and a series 300?
Anthony Gallegos
Yes. Don, thank you for the question. As we — as I noted in my comments, we actually have 2 of these signed up now, and we’re about to finalize the third contract, which will support the decision to move forward with that. And the reason I point that out is I think in those 2 customers already, you see drivers for the conversion. In one case, it’s a customer that the rig has been with, now we’re approaching a year.
And we’ve talked on earlier calls about how we’ve, as an industry, as we’ve moved deeper into the resource play — the unconventional resource play, especially being driven by the [A&D] activity among our customers, M&A, things like that, they have larger acreage positions, they’re positions are more contiguous. So this customer in particular is a great example of someone who is very, very happy, obviously, with the 200 series rig. It’s done them a fantastic job. But as they move deeper into their playbook, the laterals need to get a little longer.
And there’s always risk, I think any customer would tell you, when they change rigs, change customers.
So in that particular case, we were able to present him the best of all worlds. This is a really great rig that’s done you a fantastic job. You know it. It knows you, the crews, your team, everyone’s worked together. We know how you and ICD would like to do things. So for some increased dayrate which justifies the investment which we’ve made, also compensates us for the rig’s enhanced capabilities, we can give you the best of both worlds. So that’s an example there where it’s just really the evolving need of the customer. Really proud that we were able to do that with them.
In other cases, certainly, the 300 series rig, its specifications, its capabilities are where we are seeing increasing demand being driven by some of the same reasons. In those cases, sometimes it’s a customer that we — maybe there’s a high-grade opportunity. Maybe they’re not actually increasing the net number of rigs they’re running, but we may be able to take another rig’s position. They’re not based on price but one based on operational performance, reputation, history, and second, the rig specification. So look, these are things that we don’t have to do, things that we can offer our customers more options, if you will. And it makes financial sense for us.
To your second question regarding the dayrate differential, again, it depends on where the customers’ requirements are in that spectrum. There are some people out there, for example, that are drilling and want to drill laterals that are 3 miles in length. That’s on the extreme edge. There’s others where it’s 15,000 feet or less, I should say. So the dayrate differential ranges anywhere from 1,000 to 4,000 a day is kind of where we see that. That’s what we’re seeing in our own fleet. And that’s where we would — that’s the range that we would put out there, Don.
Don Crist
I appreciate all that color, and it makes total sense to me. My second question, as dayrates get to a point where you’re more apt to sign longer-term contracts, can you talk about some of the mitigating efforts you’re taking towards the cost side i.e., are you doing things on the labor side? Or are there long-term cost side that may mitigate increases in cost going forward as you tend to lock in mid-30s, say, contracts going forward?
Anthony Gallegos
Absolutely. So we would not sign a term contract without escalation provisions in it, not just for labor, I mean, that’s kind of where — I mean, as you know, that’s where most of our cost is, at the operating level, but also for R&M, rig supplies, things like that. And we typically would use the oilfield and machinery index as a way. You set a benchmark going into the contractual period, and then you’d have an ability to escalate. Sometimes your client will put some minimum threshold below which you can’t put that increased cost to them. Obviously, our preference would be for no threshold, just it is what it is.
But we — at ICD, we’ve rolled out 3 pay increases since November of last year. The last one went into effect June 1. And even in the contracts where they weren’t term because obviously we’ve just started signing term, we’ve been very effective at having most of the customers agree to allow us to pass that on. Look, it’s to their benefit as much as it is ours in terms of retention and everything else. So yes, if we sign a term contract, there would be escalation provisions in it. Otherwise, we just can’t do that. I don’t have to tell you about the world that we live in today.
Don Crist
Exactly. And one kind of macro question, if I could squeeze it in at the end. In the past, we have talked about rumors in the industry that the majors and larger independents could add upwards of 50 rigs going into year-end. I think your peers are kind of confirming that as well. But since our past conversations, has anything really changed there in conversations with your customers? And do you think that 50 is still kind of a ballpark number that we could add going into, call it, fourth quarter or early first quarter next year?
Anthony Gallegos
Yes. I think, no, nothing has changed. If anything, I think the outlook has only gotten better, Don. And look, our expectation would be that that’s the minimum. That gets added over the next 12 months. Very bullish about where things are right now. If you think about kind of how we got here, there’s been kind of 2 tranches so far of incremental demand. The first would be coming off the pandemic bottom.
I think we would all agree for the most part, that growth was driven primarily by the privates. They picked up more than 2/3 of the incremental rigs coming off the pandemic. And then we rolled into this year and it’s — the privates have continued to add, but you’ve seen some of the larger — well, independents and some large independents begin to pick up some rigs. So I think there’s another leg up in demand that’s coming. I think we will begin to see that as the 2023 CapEx programs get announced. And I think that’s going to be driven by the large independents and even the super majors based on some of the conversations that we’re having with people.
So we’re pretty comfortable with that range that you gave in terms of incremental demand for next year. This cycle, as you know, it’s played out so differently for all of us, especially compared to prior cycles. I mean, you’ve got just a huge ramp-up in demand. But on the supply side, you look at what’s happened there. I mean, our customers’ requirements of their contractors have increased in terms of having systems and processes there to underlie operational integrity. The rig that they require for U.S. unconventional work has changed as well. We’ve gone beyond just needing to be pad-optimal, needing the heavy drawworks off the ground to having systems and processes in place to underlie the operational integrity.
And then the thing that — on the supply side, we’re dealing with now or as we reach deeper into the inventory of stacked rigs, these rigs have been stacked for 2 years plus, CapEx requirements are going up. And just really glad and proud to see the service side of the industry demonstrate the same types of financial discipline that we’ve seen our customers display over the last couple of years. And all of that says that, look, demand is going to go up, supply is going to be constrained because of the reasons I just noted. And the market is going to find equilibrium pricing, and all that tells me it’s higher than where it is right now. So we’re very excited about the next couple of years, but especially about the next 12 months, Don.
Operator
The next question comes from Jeff Robertson with Water Tower Research.
Jeff Robertson
Anthony, given your optimism about the market over the next 18 months at least, how should we think about the portfolio mix of your contract structure between what you’d like to lock up longer term and what you’d like to keep at shorter term?
Anthony Gallegos
Yes. So thank you for the question, Jeff. As you probably know, we’ve been intentionally short term in our posture up until, really, this summer. And with where dayrates have gone, our ability to have some pretty good cost discipline, margins now are as good as they’ve been in a long time. So by agreeing to take on some term contracts here over the summer, we’re definitely not making a call on peak pricing.
While margins have gone up, as I just mentioned a second ago, so as CapEx requirements as well. So — and not all of our customers necessarily want to go along on contracts. That’s the other thing. So where we are is, especially where margins are today, we have the ability to put some term on the book to go ahead and lock in some margin, which will give us some cover and dry powder to continue the fleet expansion, which is underway.
So what you said is right. Where we are is we’re not going to go and lock up all of our rigs. We want to take a balanced portfolio approach. We think that makes sense for where we are. We don’t want to have everything rolling over in December of 2023. For example, we want to stagger the expiration of our contracts. And we’re going to look at it as a portfolio. But certainly, I would expect as we round out this year, as we begin to have serious conversations with customers around their needs next year, there’s probably going to be a few more opportunities for us to continue to take some term, especially around these incremental rigs that we’re looking to bring out over the next 12 to 15 months.
Jeff Robertson
Does the tightness in the market with — for the 300 series pipelines or spec rigs, does that allow you to push back against somebody who would say, okay, I want a longer-term contracts, and you say, look, if you don’t take it, there’s plenty of people who want these rigs. So you’ve got more leverage, I guess, in those discussions? Is that [indiscernible]?
Anthony Gallegos
Yes. Certainly, the relationship today and the dynamics is different than it’s been for 6 or 8 years. And with the increasing and evolving need of our customers, both current and prospective, and the very limited supply of that class of rig, not only are we able to receive or secure better dayrates but better contract provisions. There’s a lot of things that get buried in contracts, reimbursable costs, things like that, that we don’t necessarily talk about on these calls. But it’s also one of the contributors to the better margin per day that ourselves and others are able to report. Do you want to add anything, Phil?
Philip Choyce
Yes. I think our willingness to sign a longer-term contract, if you look at our backlog today, that goes into next year, it’s just a couple of rigs really. There’s 3 rigs that actually have backlogs digging in the next year, 2 of them are 300 series rigs, 1 is a 200 series rig. And if you just look at the margin in those rigs on the high end, on the 300, those rigs are going to generate $17,000 a day margins for us, which is, I mean, that’s something we’ll — that’s an interesting term contract for us because it’s going to reward us for the — what we see as an improving pricing environment.
Obviously, operators want to lock in a lower rate as they can. So that’s the dynamic, the push and pull between our willingness to sign a contract today and are — and the operator. It’s really — are they willing to compensate us because there’s — the market’s tighter, it’s getting tighter. Pricing is improving. And so we need to — when we’re signing a longer-term contract, we need to get that in that term contract or it’s going to be hard for us to look at it.
Operator
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
Okay, Betsy. We appreciate that. I want to say to everyone, I really appreciate everybody taking the time to dial in this morning. Just want to end on a quick safety moment. I want to remind everybody that kids are starting to go back to school. Over the summer here, we’ve gotten — probably all have gotten out of the habit of paying attention to school zones and on highways and things like that. So I just want to remind everybody here over the next week or two, the kids will be returning to school. So let’s watch out for them.
Hope everyone has a good, safe end of their summer. Again, thank you, everybody. We’ll end the call.
Operator
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
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