Q2 2023 Independence Contract Drilling Inc Earnings Call
Participants
Philip Choyce; EVP & CFO; Independence Contract Drilling, Inc.
Anthony Gallegos; CEO; Independence Contract Drilling, Inc.
Don Crist; Analyst; Johnson Rice
Steve Ferazani; Analyst; Sidoti
Dave Storms; Analyst; Stonegate Capital Markets
David Marsh; Analyst; Singular Research
Jeff Robertson; Analyst; Water Tower Research
John Daniel; Analyst; Daniel Energy Partners
Dick Ryan; Analyst; Colliers
Presentation
Operator
Good day and welcome to the Independence Contract Drilling's second-quarter 2023 financial results conference call. (Operator Instructions) Please note today's event is being recorded. I would now like to turn the conference over to Philip Choyce, EVP and CFO. Please go ahead.
Philip Choyce
Good morning, everyone, and thank you for joining us today to discuss ICD's second-quarter 2023 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 period to differ materially from what we talk about today.
But for complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for our full reconciliation of net income and loss to adjusted net income and loss, EBITDA and adjusted EBITDA, and for definitions of our non-GAAP measures.
And with that, I'll turn it over to Anthony for opening remarks.
Anthony Gallegos
Hello, everyone. Thank you for joining us for our second-quarter 2023 earnings conference call. During my prepared remarks today, I want to talk about the following. First, I want to highlight some significant steps we took during the second quarter toward important strategic initiatives. Second, I want to update you on the transition efforts around our Haynesville fleet, which is essentially complete.
Third, I want to talk about the current market for super-spec, pad-optimal rigs and how ICD is performing. Lastly, I want to close out talking about some things we're doing to position ICD for the future.
First, just a few comments on the quarter. Overall, ICD's second-quarter results came in ahead of expectations in terms of revenues, margin per day, and adjusted EBITDA. I'm particularly pleased with how reported margin per day held up in the face of market headwinds, driven primarily with our Haynesville market, buoyed by sequential improvement in reported cost per day. Overall, adjusted EBITDA came in at $18.7 million.
During the second quarter, we took the first step in the most important strategic initiative for our company, which is de-levering our balance sheet. I feel this way because in addition to delivering industry-leading service and professionalism to our customers, reducing the debt level of our company is the most impactful action we can undertake.
During the quarter, we redeemed $5 million of convertible notes at par and also reduced revolver borrowings, while at the same time, improving our net working capital position. I'm pleased that we were in a position for our lenders to accept our offer to redeem $5 million of our convertible notes at par at the end of the second quarter.
Also during the second quarter, we essentially completed our fleet geographic rebalancing process. As a reminder, ICD started 2023 with 10 rigs working in the Haynesville market and 10 rigs working in the Permian. We were more levered than any other drilling contractor to the Haynesville. And in light of the softening we saw early this year, we made the decision to relocate several rigs from the Haynesville to the Permian.
The choppier Permian market we experienced in the second quarter impacted the pace at which we were able to recontract ICD rigs relocated from the Haynesville. As of today, we have four rigs remaining in the Haynesville, and three of those are currently contracted. Although it is possible that we relocate additional rigs from the Haynesville, depending on how the markets develop over the next 12 months. For the time being, our rig transition program is complete.
Overall transition cost, including trucking and crew transition cost, totaled approximately $2.8 million during the second quarter and $3.4 million in aggregate, below our initial estimates of 4 million total.
Now turning to market conditions in our target markets. The overall US land rig count is down 105 rigs year to date through the end of the second quarter. Although the Permian market has remained strong, consistent with our expectations at the beginning of this year, we have seen some softness resulting in an overall Permian rig count decline of about 11 rigs caused by weaker commodity prices early in the second quarter and the recent banking issues.
These factors resulted in some reshuffling of rigs by E&P operators and more rig-on-rig competition. In spite of all this, ICD increased its Permian contracted rig count by 20% year to date in the face of numerous competitive pressures. I think that speaks to the quality of our people and equipment and our strong brand.
We remain optimistic about market momentum reaccelerating in the back part of this year, primarily in the Permian, based on recent moves in commodity prices, our customers having better access to credit, current customer inquiries and discussions we are having, and our expectation that WTI will continue to strengthen in the back half of 2023 rolling into 2024. Also think the effects of recharged E&P capital budgets next year will provide additional boost to our Permian market.
While we expect some rigs to go back to work in the Haynesville, we believe that gas-driven gas markets will remain challenged for at least the rest of this year. We have, however, seen inquiries for work in the Haynesville pickup over the last couple of weeks.
In addition, Permian -- permitting activity for the Permian in June increased 25% month to month. And overall permits for US land year to date compared to 2022, you're up slightly in spite of the softer commodity prices we saw early second quarter. Based on all this, we believe US land rig count is finding a bottom as we speak and will begin increasing in the coming months.
On the day rate front, current leading edge, super-spec day rates in the Permian are coalescing in the low- to mid-$30,000 range, including adders. Right now, there are minimal data points for spot day rates in the Haynesville. But I would expect that you're just a little bit lower, maybe $1,000 to $2,000 a day compared to the Permian.
In terms of enhancing our fleet, we are planning some 200 to 300 series conversions in the back half of this year, one of which is in process in connection with a contract extension into mid-2024, which we just executed for a rig working in the Permian Basin at a mid-$30,000 day rate and including the adders. In this arena, we are seeing customer interest in high-torque top drives, iron roughnecks, and drill strings increase as a function of E&P's increasing well lateral length and their unrelenting focus on drilling efficiencies.
These are trends we expect will continue and our vestors should feel good knowing that the majority of our working rigs already have these capabilities embedded and the rest can be outfitted to have these capabilities with very modest amounts of CapEx.
As I close out my prepared remarks, I want to mention our efforts regarding our technology rollout, which we call ICD impact, which accelerated during the second quarter. Our strategy in this arena has been to leverage ICD as youngest rig fleet in the industry and the years of effort and investment made by our third-party partners by working with their professionals, collaborating with our customers, and applying the knowledge, skills, and insight of our employees.
We have technology systems deployed on approximately 30% of our active rigs today with objectives to improve this percentage over time as customer demand warrant. We are excited about what ICD impact means for our customers and other stakeholders going forward. I'll make some additional concluding remarks before opening the call up for questions. But right now, I'd like to turn the call over to Philip to discuss our financial results and outlook in a little more detail.
Philip Choyce
Thanks, Anthony. During the quarter, we reported an adjusted net loss of $1 million or $0.07 per share and adjusted EBITDA of $18.7 million. We operated 15 average rigs during the quarter. This excludes two average rigs' earning revenue on an early termination basis during the quarter, and early termination revenues during the quarter were $5.1 million.
Moving on to our per-day statistics, these statistics exclude both the early termination revenues and transition expenses. Although we had a number of rigs moving between customers and locations and our overall operating days fell by an average of 4.4 rigs compared to Q1, we're pleased we saw only minimal degradation in our revenue, cost per -- cost and margin per day statistics.
Revenue per day during the quarter was $34,467, representing a slight decrease from the first quarter. Cost per day during the quarter was $19,005, representing sequential improvement. Overall margin per day was $15,462, representing only a 1% sequential decline compared to the first quarter.
SG&A cost were $5.2 million during the quarter, which included $1.3 million of stock-based and deferred compensation expense. These costs declined sequentially by 22% overall. Breaking out the components, cash SG&A expenses decreased sequentially by 21% compared to Q1 due to lower incentive compensation accruals and cost cutting efforts implemented during the quarter.
Non-cash stock-based compensation expense also decreased sequentially in this case by 27% due to lower -- due to the effect of a lower quarter and stock price and variable accounting on performance-based stock awards. Interest expense during the quarter aggregated $8.3 million. This included $1.2 million associated with non-cash amortization of debt discount and deferred issuance cost, which we excluded when presenting adjusted net income.
Tax benefit for the quarter was de minimus. During the quarter, cash payments for capital expenditures, net of disposals, were approximately $11.5 million. This includes final payment of capital expenditures on rig react -- on our rig reactivation program, including our 21st rig that reactivated at the beginning of the quarter. It was approximately 5.1 million of CapEx accrued in accounts payable at quarter end.
Breaking out $11.5 million cash payments on CapEx during the quarter, approximately 53% related to rig reactivations and 200 to 300 series conversions, 35% related to maintenance CapEx, and 12% related investment in drill pipe capital inventory and spares. For the remainder of the year, so when we move forward towards 18 or so working rigs by yearend, we expect capital expenditures during the back half of the year to aggregate approximately $9.5 million, which assumes 200 to 300 series conversions and approximately $1.5 million in tubular purchases.
Moving on to our balance sheet. As Anthony mentioned, our strategic focus has shifted from rig reactivations to overall debt reduction. This also includes steady improvements in our working capital position as well. We made progress towards both of these goals during the quarter. We repaid $5 million of convertible notes at par and also reduce revolver borrowings by $5.3 million during the quarter.
We were do -- we are able to do this while slightly improving our net working capital position as well. Adjusted net debt at quarter end was approximately $191.2 million, also decreased from March. I want to point out our adjusted net debt statistics include accrued interest we have elected to pay in-kind on September 30, of this year.
Our financial liquidity at quarter end was $19.1 million, comprised of cash on hand of $5.6 million and $13.5 million of availability on our revolving line of credit. This is in addition to the net working capital improvement I just mentioned.
Now moving on third-quarter guidance. We expect operating days to approximate 1,240 to 1,250 days, representing approximately 13.5 average rigs earning revenue during the quarter. Let's exclude rigs earning revenue on an early termination basis, which will be minimal during the third quarter. But margin per day to come in between $14,250 and $14,750 was the sequential decline related to lower day rates on contract renewals.
We also expect some sequential cost inefficiencies during the quarter associated with a lower operating base and reduced operating days. From a contract mix standpoint, the vast majority of our rigs are now operating on short-term pad-to-pad contracts and reflect the current day rate environment. For example, during the third quarter, we expect only 25% to 30% of our revenue days to be earned on contracts that were entered into prior to March 31, of this year.
Unabsorbed overhead expenses will be about $600,000 and also not included in our cost per day guidance. And as Anthony mentioned, our Haynesville, the Permian transition program is complete. We do not expect to incur any transition expenses during the third quarter.
We expect third-quarter cash SG&A expense to be approximately $4.3 million with a small sequential increase primarily tied to expected increases in recruiting and onboarding cost because we began staffing up for expected reactivations in late third quarter and early fourth quarter. Stock-based compensation expense is expected to be approximately $1.9 million, assuming no material changes to our stock price as of today, that would further impact variable awards.
We expect interest expense to be approximately $9.5 million. And of this amount, approximately $2.4 million will relate to non-cash amortization of debt discount and deferred financing cost. Depreciation expense for the third quarter is expected to be flat with the second quarter. We expect tax benefit to be flat with the second quarter.
With that, I'll turn the call back over to Anthony.
Anthony Gallegos
Thanks, Philip. Before opening the call up for questions, I want to briefly summarize where we are as we enter the second half of 2023. While this may not be the year that we thought it would be, 2023 is proving to be a very important year for ICD, initiating our efforts to delever our balance sheet, repositioning our rigs to a more appropriate geographic positioning and balance, and executing on our technology pathway are all very strategic initiatives which are happening. And these initiatives will provide value to the stockholders, customers, and employees of ICD in the coming years.
I would like to thank our many operations, support, and corporate team members who work hard every day to deliver high levels of safety, performance, customer service, and professionalism, which our customers expect from ICD and which we expect of ourselves.
With that, operator, let's go ahead and open up the line for questions.
Question and Answer Session
Operator
(Operator Instructions) Don Crist, Johnson Rice.
Don Crist
Good morning, gentlemen. How are you all today?
Philip Choyce
Doing good.
Anthony Gallegos
Doing well.
Don Crist
I wanted to explore the topic of adding rigs back in late third quarter, fourth quarter, and possibly into '24. We've heard several anecdotes from other companies and just wanted to get your take on what gives you confidence. Are there significant tenders that are out there today? Or they just conversations today?
Anthony Gallegos
Certainly, Don, the nature of the discussions with customers has changed over the last couple of months. I think obviously, strengthening commodity prices helped the macro picture in the US and what's happening there, I think, it help. I think those things along with some others have given some customers some confidence that they can step back in.
And just to give you a little transparency, we're not doing a lot of work today for the supermajors. We do work for the independents, and we do a lot of work for privates as well. And it's in that last bucket where we've probably seen the most change over the last couple of months with the private E&Ps.
Remember also, they were the first ones about a year ago to start laying down rigs that sat on the sidelines the last few quarters. And I think as we look out over third and fourth quarter, for us at least, that's where we see opportunities to bring rigs up.
Don Crist
And just to take that a step further, in the Haynesville arm, are you getting into conversations now, given that the [24] strip is over $3, to actually add some rigs back in the Haynesville? I know that's not going to be a priority since you moved a lot of rigs out of the area, but is that market starting to see some tightening versus loosening over the past several quarters?
Anthony Gallegos
Yes, certainly over the last couple of weeks, Don, again, those discussions have also picked up as well. We bottomed out at two of the four rigs that we had earning revenue there. We're three today. Pretty optimistic. The fourth one want to go back to work before we talk to you guys again. And the rig count over there has bottomed out around 44 rigs. That's down from mid-70, so quite a drop.
Strip has moved. I was looking at it earlier this week, and you look out past October this year, it's above $3. And in January, it's over $3.70. And that -- what we hear from customers, $3.25, $3.5; they're thinking about growing. And we're pretty optimistic about being able to put that fourth rig to work probably in the third quarter.
Don Crist
I appreciate that color. And just one final one for me on the conversions. Are those customer-driven conversions from 200 series, the 300 series? And how many more of those do you think you could do over the next couple -- several quarters?
Anthony Gallegos
Yeah, it's been great. I'm really proud that we were able to sign this second one up. In both of the instances, they were customers that were using our 200 series rig. It's doing a great job for them. Obviously, they were very happy. Our customers would like maximum flexibility as they look out over the coming quarters and coming years to be able to take a rig and work across the spectrum of projects which they have.
So in both cases, the operators -- customers were very supportive of the conversion to 300 series capability. And I would point out in both cases, we were able to -- we're going to earn a premium day rate relative to what that rig would have earned, had we not converted it. So as we've -- this will be the second one that's in motion as we speak. We have a handful more that we can do.
We have some kits on the ground. Our strategy is to use those kits when there's opportunities to earn that incremental payback over the course of the contract. And we've been able to do that now twice. So it's flexibility for us. Are those -- when we talk about our 200 series rigs, they're super-spec, they're pad-optimal. They have all the bells and whistles that the standard super-spec, pad-optimal rig has.
But as the unconventional play continues to play out, as the laterals continue to get longer, as our -- if our customers need that added capability, we have the flexibility to be able to offer it.
Don Crist
I appreciate all the color. I'll turn it back. Thanks.
Anthony Gallegos
Thank you, Don.
Operator
Steve Ferazani, Sidoti.
Steve Ferazani
Afternoon, Anthony, Philip. Regarding your commentary around day rates in the Permian and then your guidance for margins going into 3Q, it sounds like day rates might be coming down a little bit, but certainly not necessarily significant, given how much rig count has dropped. What are you seeing in day rates? And are the conversations getting harder?
Anthony Gallegos
Yeah, day rates have softened some, Steve. But just to put it into perspective, when you look at what's happened year to date, the Permian market is only off a dozen or so rigs and 4% since the beginning of the year. So there has been some trimming as you guys know, but there's been some people that have added some rigs as well. There's a lot of churn in the background that you probably don't have the insight into. But regardless, day rates have obviously held up pretty nicely.
When you look at the margin per day that we just reported, very proud of that. We're guiding down a little bit as we think about Q3, and we're saying Q4 is going to be flat with Q3. And if you think about that, especially on a historical basis, for these kind of margins, that's really good. And it's another reason why we're very optimistic about what the next several quarters are going to allow ICD to do on those big, important strategic initiatives that we have underway.
Steve Ferazani
What's your confidence level now in getting some rigs back to work in Q4?
Anthony Gallegos
Very high.
Steve Ferazani
Okay.
Anthony Gallegos
Very high. We're going bring out -- I think, it's three minimum, before the end of the year.
Steve Ferazani
Really? Okay.
Anthony Gallegos
Yeah, that probably happens sooner rather than later.
Steve Ferazani
Excellent. Any kind of color you can give around the early termination with those rigs in the Haynesville? And did they have a lot of term left given the $5 million?
Anthony Gallegos
Yeah, one is still on contract, on standby, but through November of this year. The other one, it's early term. Provision ended here about 10 days ago. So the three rigs that we have working in the Haynesville today, only one is sitting there earning standby. The other two are on day work basis.
Philip Choyce
Yeah, so the $5.1 million. it was really three rigs and pretty much all of it ended at -- by the end of the second quarter.
Steve Ferazani
Okay, great. You took a lot of costs out here, obviously, helped out a lot. How much of that do you think comes back with getting those rigs back to work? Was that a lot of very temporary cuts? Or was there anything you took out that could be permanent?
Anthony Gallegos
On the SG&A side, some of it in the second quarter clearly was -- we weren't in hiring mode. We'll go back to that. And so when you think about the sequential guide up from the second quarter to third quarter, that's what we're really talking about there. There's probably about $1 million in SG&A that I would consider permanent, which is really some headcount type of things that we've done and some other efficiency things that we've put in as -- and then on the operating side, that's really temporary from the standpoint of operating cost. That isn't going to go up and down as the rig count went up and down.
We will have some choppy -- when you talk -- the earlier question on margins, part of the guide downs, not debt all day rat. Some of it, we're going to be -- it's going to be a choppier third quarter as we put rigs back to work and things like that. There's going to be some churn, and that does affect your cost per day statistics.
Steve Ferazani
Understood. Perfect. Thanks, Anthony. Thanks, Philip.
Philip Choyce
Yes sir, Thank you.
Operator
Dave Storms, Stonegate Capital Markets.
Dave Storms
Good morning.
Anthony Gallegos
Good morning, Dave.
Dave Storms
Morning. Just hoping you could touch on some of the banking issues that you mentioned that were seen in the quarter and looks like most of them have copied her up. Do you see any potential for any of that to rear its head again either the next quarter or further on down the line?
Philip Choyce
Yeah, so what I was referring to was really access to credit on the part of our customers. And we think and you guys know better than I do, you think back to what was playing out in the second quarter with -- especially around the regional banking crisis, redeterminations around credit lines, and stuff like that. Just -- we think those issues, while they're -- may not be completely resolved, we think they're better today than they were in early second quarter.
One anecdote I would give you guys is we were awarded -- verbally awarded a program back in March. It's a big program out in the Permian as a private E&P operator. And March or a May start, will May slip to June, slip to July, well, now we're in the process of papering that up. And what's changed is the financing side of the project for the customer, and that's an antidote that I would share with you guys. But it is my understanding and view that I think our customers will have more access to capital, which -- we talked about the reasons why. Commodity prices, other things like that, that are going to help drive that.
Dave Storms
That's very helpful. Thank you. And then the other thing you mentioned just found free counts, finding a bottom with the increase expected in the coming months, can you just help us get a sense of -- when that demand does come back, the breakout between the demand for 300 series rigs versus 200 series rigs?
Anthony Gallegos
Yeah. [Where you] bottomed out in this, I think, 660s. Where we are right now, maybe it goes to 650. When you look at where the rig count -- rigs are working and rig count, about half the rigs are working out in the Permian. We would expect that percentage to continue and even grow. In the Permian, there's the Midland Basin work, there's the Delaware Basin work. I think you would expect to see some adds in the Delaware Basin just because of the productivity that you're hearing E&P's talk about out there.
So what's important for us is that if -- and we're not making a call and saying the entire market is going to move to 300 series specification. But what's important for us and our stockholders, if that's where it were to go, we have a very clear pathway toward being able to meet those opportunities through that incremental demand.
Dave Storms
That's perfect. Thank you for taking my question. And congrats on the quarter.
Anthony Gallegos
Thank you, Dave.
Operator
David Marsh, Singular Research.
David Marsh
Hey, guys. Thanks for taking the questions. First, Phil, if I could, I just wanted to ask a question about this convertible note repurchase. Looked like cash flow statement, it has been $5 million exactly the repurchase, but then you said par plus accrued, so this was -- wanting to get a little color like to make sure I understood. Did you retire $5 million in principle of this note?
Philip Choyce
Yeah, so it's $5 million and accrued interest was probably a couple of hundred thousand dollars higher, and that would be up in the other part of the cash flow statement and the operating piece. So it's $5 million pay down at par, yes.
David Marsh
Got it. And are they continuously callable at par at this point?
Philip Choyce
There is a mandatory offer provision where we make an offer at the end of each quarter through 2024 to pay down at par. And so it's $5 million each quarter till the end of this year. Then, it's $3.5 million each quarter through next year. And this was the first quarter. June 30, this was the first -- under the [NDA], this was the first offer that we made and then they accepted it.
David Marsh
Got it. Got it. I understand. And then, are you guys still picking at this point or/and could you kind of update us on plan to possibly transition to cash interest payment on this?
Philip Choyce
Yeah. So I think what we've said publicly is our plan was to pick through March of -- through March '24, certainly with the opportunity to seize picking at September, where we sit here today, assuming the mandatory offers are being accepted. And that's what we think is the most likely scenario. Though, that's up to our lenders. Then we probably would be funding the mandatory offers, but we probably go ahead and pick through March '24. And then, we would -- our plan would be to stop picking at that point in time.
David Marsh
Got it. I'm guessing that the refinancing market is still not quite favorable enough for you guys to consider some type of an open-market refinance at this point.
Philip Choyce
So the refinancing window under the indenture doesn't open up until September of next year. We obviously want a little bit of a down market here as far as our EBITDA and reported EBITDA. So it wouldn't be ideal for us to do something now, in my opinion, just because it's a negotiation. It's pretty early as far as when that window opens up. And I think with the opportunity to get some more rigs out, I think that there's probably some better opportunities and discussions we can have next year.
David Marsh
Yeah, yeah, I would absolutely agree. I just trying to put a finger on the pulse of it. You guys moved -- you guys called out some cost in the press release with regard to moving rigs from the Haynesville to Permian, $600,000 in Q1, $2.8 million in Q2. How many rigs were moved in total?
Philip Choyce
Six rigs in total.
David Marsh
Okay, perfect. That just helps understand -- helps in understand the cost of moving one. So that's really helpful. Appreciate it. That's all I have. Let me yield to someone else here.
Anthony Gallegos
Thank you, David.
Operator
Jeff Robertson, Water Tower Research.
Jeff Robertson
Thank you. Good morning. Anthony, is -- has the churn maybe slows down in the Permian Basin? Do you expected that point that day rates will start to firm up and margins start to improve as you put rigs back to work late this year and heading into '24?
Anthony Gallegos
Yeah, I think it's going to be a little -- a quarter later than what people may expect, Jeff, and that's the reason is (inaudible) the rig laid down, lots of big players in the business maintain a good discipline in pricing. As there are opportunities presented for people to step into the bearish box, they're going to be aggressive in trying to get their rigs out. The good news is I think it's a relatively limited number of rigs that we're talking about. So because of that dynamic, the margin probably lags the uptick and utilization by quarter.
That's why we're laying out for you guys, a slight decrease in the third quarter and then sideways for the fourth quarter. But very optimistic about 2024. There's only been a 100-rig decline throughout the United States over this year, as you know. And very few of those have been in the Permian. So the inflection to get back to pricing increases, I think, is probably sooner than people may realize, but it's going to be a little longer or a little later than we would like.
Jeff Robertson
Do you get the sense that any customers are starting to worry about how they might get a rig back today? And so if they start to look at the back half of '24 and maybe a more optimistic view of gas markets then into '25?
Anthony Gallegos
Yeah, absolutely, Jeff. We've had guys actually have that conversation with us as they're starting to think about 2024. It likely becomes a challenge for them. I think one of the biggest reasons is we talked I think on the last call about how activity in the Haynesville is drifting south and west.
And what's important to note from an equipment standpoint is as it does, it's typically deeper push. All the laterals are getting longer, and that just requires a bigger rig. And if you want to look at some extreme examples, look at what -- I think it's the Comstock that made an announcement earlier this week and what they're doing in the extreme western edge of the Haynesville. This is the stuff over in Texas in Robertson County in that area.
The well results that were published earlier this week, I think, it was 34 million cubic feet a day of gas. That's very similar to what a lot of the E&Ps are seeing in the Haynesville. And then as exciting as that, now they're going to test the deeper [Bolger] bench over there as well. And the reason I point that out is, like I said, remember, the Haynesville as it moves west, it gets deeper, the hook loads get higher. You're talking big equipment, and there's a limited number of those in the industry. Million-pound-type rigs, big setback capacity, things like that. And I think that bodes -- that dynamic along with just the general Haynesville picking up is going to bode really well for contractors that have that kind of equipment. And of course, we're one of them.
Jeff Robertson
So that plays migrating toward your rigs in terms of the specifications needed.
Anthony Gallegos
Absolutely. The 300 series. Yes, sir.
Jeff Robertson
So if you mentioned that you anticipate that the lenders will accept the redemption offers. So that really drives or should allow ICD to naturally delever between producing the principal amount of those convertible notes, which also I guess, ultimately decreases the refinancing burden. But also, it appears you should still be able to add cash to the balance sheet. So your leverage profile is that refinance window opens up. It should mention late next year the company's just natural leverage ratio starts to look a lot better and maybe have more opportunities. Is that a fair way to think about it?
Anthony Gallegos
Yeah, I think, certainly, compared to the guidance that we've provided in the past because I think in the past, we had not really spoken much about your and then accept because we didn't know until -- what their plans would be until we saw what they did this quarter and was then accepting those mandatory offers that certainly accelerates kind of the debt paydown that's beginning now as opposed to really in March of next year so.
Jeff Robertson
Thank you very much.
Anthony Gallegos
Thank you, Jeff.
Operator
John Daniel, Daniel Energy Partners.
John Daniel
Hey, guys. Thank you. Anthony, I apologize. I missed part of the prepared remarks. Can you tell me what the working rig count is today?
Anthony Gallegos
We have 14 rigs today earning revenue at ICD.
John Daniel
Okay. And then, --
Anthony Gallegos
One of them, it's on their early term -- or on standby rather.
John Daniel
Okay, so 14 are turning to the right or 13?
Anthony Gallegos
13 are turning to the right.
John Daniel
Perfect. Okay. And Don asked some pretty good questions. I'm going to follow up with -- add on to his, but I know you mentioned some of the incremental rigs that you're going to deploy likely go to private operators. But I'm curious, you guys are probably pretty busy getting ready for earnings and all that. But if you listen to all of the E&P earnings calls last week and so far this week, the majority of them are saying flat activity, maybe bleeds a little bit lower. And so I'm curious as your sales guys are getting inquiries from customers, how often -- are you catching any disconnects where the E&P's are publicly saying one thing, but they're calling you and asking something else? And obviously, you don't want to give names, but I'm just curious. Your thoughts?
Anthony Gallegos
Yeah. No problem, John. I wouldn't say it's a disconnect. I think it's just more of the perspective into the market. We're not working for any of the supermajors today, although we have in the past. And so when we're into these discussions is with large independents and especially on the private side. And the opportunities that we're pursuing with the large independents, for the most part are high-grade opportunities where they have an underperforming rig or a rig that may have lesser capability than a rig that we have we can offer.
And those are the opportunities with the independents. Where we do see or where we are seeing the incremental adds is more with the privates, and we talked about that earlier in the call. As I look out over third quarter and certainly by the end of the year where I see three rigs going back to work. Two of those are 300 series rigs that we have that we're working just a couple of months ago.
We probably put another 200 series out. The question is do we upgrade it or not to 300 series capability, and that's going to depend on the requirement that we're pursuing and whether or not we think we can get paid for it, right? So I wouldn't say there is much of a disconnect. It's just that where we fit into the market with those three classes of customers.
John Daniel
Okay. If you go back the last several months, you were probably more clairvoyant than others with respect to the Haynesville rig count where it might trough and if you use [Baker] as your proxy, I think it's low-40s right now and I think it was in the last seven days that, you know, when times were hopping. Where do you think we hit in '24? What would the increase suggest we could be at at '24?
Anthony Gallegos
Look, if you look at the strip, you listen to what customers say their -- what price they need to stimulate activity. And I can see a dozen rigs easy over there. And that's really ignoring what's happening in that extreme western part of the play, which I described a second ago but just looking at the Haynesville proper that we've all known. I see a dozen (inaudible)
John Daniel
Okay. And I mean, obviously, that happens if we have a cold winter, things change pretty fast. But the inquiries today don't necessarily put us back to where we were in Q4 '22. That's a fair statement. It's knowing the store early.
Anthony Gallegos
Correct. But remember your available supply is lower than it was too, so you probably see a bigger pricing response at a lower rig count in the Haynesville than you needed before.
John Daniel
Yeah, awesome. Thank you for very granular answers.
Anthony Gallegos
Thank you, John.
Operator
Dick Ryan, Colliers.
Dick Ryan
Thank you. So Anthony, on your strategic initiatives, the technology pathways, where are you in that rollout? Can you provide a little commentary? What's your ultimate goal? Will that help you be in a better position to take some share in the market? Can you just provide a little more commentary on that.
Anthony Gallegos
Yes, great. I appreciate you let me talk about, Dick. We haven't talked a whole lot about that. Look, like all other industries out there, I mean, we've expected the technology and demands for technology and appreciation for what it's going to do would make its way into oil and gas. And I think it is in a big way. We've chosen over the last couple of years to not get into the arms race of trying to develop this technology ourselves.
Part of that just some of the limitations that we have, but we also felt that over time, this would -- there would be a shakeout phase. So our strategy -- stated strategy is that we wanted to be a very fast second mover on this front. But in the meantime, make sure that we have the right platform in place to be able to deploy technology and we do with the AC rigs that we have, especially the control systems over half of our rigs are precise controlled rigs.
So think about your operating system on your iPhone, you've got to make sure that you have a platform in place to be able to deploy this technology. So as we rolled into 2023, as we were thinking about the business and talking to customers, it was pretty apparent to us that going forward, they are meant to have a technological offering and be able to add to our customers' efforts to be productive, that those are going to increase over the coming years. So we wanted to spend time in 2023 proving what I just described, which was to deploy third-parties technology on our rigs and demonstrate we can create value. Not just for our customers, but also for ICD and our stockholders.
So I guess the point that I'm trying to make is that that's happening now. We have four of these systems deployed. We've been very lucky because our biggest customer in the Permian Basin has been very supportive of these efforts. So we have a couple of systems that are -- being used on a trial basis. We've got some things around the edges where we are getting paid for this stuff.
Very positive results so far. We have a drill string oscillator. We have some stick/slip mitigation software, back to bottom sequencing. What we're seeing is that all of those things are being mitigated. Trip times are being improved. Where do we think this can go?
Philip and I sat around and thought about this. Look, we think they're somewhere between $500 and $1,500 a day of the incremental margin that could come to us. Now just like with all contractors, it may not get deployed on every rig that we have operating. But obviously over time, if this thing can prove its value, then customers are going to be willing to pay for it.
And I'm really pleased and proud of the third-party partners that we're working with. I appreciate the customer that we have working with us. We just haven't talked a lot about this over the last couple of years. I didn't want people to think we're not doing anything about it because we have been. It's been very quiet, but it's been very deliberate, but really pleased with what we've been able to show year to date on this front.
Dick Ryan
Sir, I appreciate the color. Thank you,
Anthony Gallegos
Yes, sir. Thank you, Dick.
Operator
Thank you. And ladies and gentlemen, this concludes your question-and-answer session. I would like to turn the conference back over to the management team for any final remarks.
Anthony Gallegos
We appreciate that. I want to thank everybody for making time to participate in today's call and giving us the opportunity to update you and talk about the exciting things going on here. Best wishes to all of you for safety and prosperity until we talk again. With that, we'll close out. Thank you.
Operator
Thank you, sir. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.
