Independence Contract Drilling, Inc. (NYSE:ICD) Q2 2023 Earnings Call Transcript

Independence Contract Drilling, Inc. (NYSE:ICD) Q2 2023 Earnings Call Transcript August 6, 2023

Operator: Good day and welcome to the Independence Contract Drilling 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 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 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 a 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 earlier 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 4 rigs remaining in the Haynesville, and 3 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 costs, including trucking and crew transition costs, 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 U.S. 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 base 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. I 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 Haynesville, we believe that gas-driven gas markets will remain a challenge 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, permitting activity for the Permian in June increased 25% month-to-month, and overall permits for U.S. land year to date compared to 2022 were up slightly in spite of the softer commodity price we saw early second quarter. Based on all this, we believe the U.S. 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 they are 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 a day rate, 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 lengths and their unrelenting focus on drilling efficiencies. These are trends we expect will continue, and our investors 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’s 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 warrants. 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.

Pixabay/Public Domain

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 2 average rigs earning revenue on an early termination basis during the quarter, and early termination of 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 are pleased we saw only minimal degradation in our revenue, 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 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 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 costs, which we excluded when presenting adjusted net income. Tax benefit for the quarter was de minimis. During the quarter, cash payments for capital expenditures net of disposals were approximately $11.5 million. This includes final payments of capital expenditures on our rig reactivation program, including our 21st rig that reactivated at the beginning of the quarter. There’s approximately $5.1 million of CapEx accrued in accounts payable at quarter end. Breaking out our $11.5 million cash payments on CapEx during the quarter, approximately 53% related to rig reactivations and 200 Series to 300 Series conversions, 35% related to maintenance CapEx and 12% related to investment in drill pipe capital inventory and spares.

For the remainder of the year, so when we move towards 18 or so working rigs by year-end, 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 reduced revolver borrowings by $5.3 million during the quarter. We were 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 a decrease 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 to third quarter guidance. We expect operating days to approximately 1,240 days to 1,250 days, representing approximately 13.5 average rigs earning revenue during the quarter. This excludes rigs earning revenue on an early termination basis, which will be minimal during the third quarter.

Net margin per day to come in between $14,250 and $14,750 with the sequential decline relating to lower day rates on contract renewals. We also expect some sequential cost inefficiencies during the quarter associated with the lower operating days 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 are not included in our cost per day guidance. And as Anthony mentioned, our Haynesville to 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 costs as we begin 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 were related to non-cash amortization of debt discount and deferred financing costs. 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 will 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 de-lever 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 in which we expect of ourselves. With that, operator, let’s go ahead and open up the line for questions.

See also Most Faithful Female Zodiac Signs and Top 30 Most Hated Countries in the World.

Q&A Session

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] And today’s first question comes from Don Crist with Johnson Rice. Please go ahead.

Don Crist: Good morning, gentleman. How are you all today?

Anthony Gallegos: Doing good.

Don Crist: I wanted to explore the topic of adding rigs back in late third quarter, fourth quarter and possibly into ‘24. We have 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 are 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 U.S. And what’s happening there, I think it helped. I think those things along with some others have given some customers some confidence that they can step back in and add. Just to give you a little transparency, we are not – not doing a lot of work today for the super majors. 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 have 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. They kind of sat on the sidelines in the last few quarters. And I think as we look out over the 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, 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?

Philip Choyce: Yes. Certainly, over the last couple of weeks, Don, again, those discussions have also picked up as well. We bottomed out at 2 of the 4 rigs that we had earning revenue there. We are at 3 today, pretty optimistic. The fourth one will go back to work before we talk to you guys again. And the rig count over there has bottomed out at around 44 rigs. That’s down from mid-70s, 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 is $3.25, $3.5, they are thinking about growing. And we are 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 to 300 Series and how many more of those do you think you could do over the next several quarters?

Anthony Gallegos: Yes. It’s been great. I am really proud that we were able to sign the second one up. In both of the instances, they were customers that were using our 200 Series rigs, 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 are going to earn a premium day rate relative to what that rig would have earned had we not converted it. So, 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 is opportunities to earn that incremental payback over the course of the contract, and we have been able to do that now twice. So, it’s flexibility for us. Those – when we talk about our 200 Series rigs, they are super spec, they are 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, 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 will turn it back. Thanks.

Philip Choyce: Thank you, Don.

Operator: Thank you. And our next question today comes from Steve Ferazani with Sidoti. Please go ahead.

Steve Ferazani: Good afternoon Anthony and 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: Yes. 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 has been some people that have added some rigs as well. There is 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 are guiding down a little bit as we think about Q3 and we are 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 are 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. We are going to bring out, I think, it’s three minimum before the end of the year. And they probably happen 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: Yes, one is still on contract on standby, in fact, through November of this year. The other one, it’s early term provision ended here about 10 days ago. So, of the three rigs that we have working in the Haynesville today, only one is sitting there earnings standby. The other two are on a day work basis.

Philip Choyce: Yes. So, the 5.1 million, it was really three rigs and pretty much all of it ended by the end of the second quarter.

Steve Ferazani: Okay. It 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 will 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 are really talking about there. There is probably about $1 million in SG&A that I would consider permanent, which is really some headcount type of things that we have done and some other efficiency things that we have put in. And then on the operating side, that’s really temporary from the standpoint of operating costs. Those are going to go up and down as the rig count gets up and down. We will have some choppy – when you talk to the earlier question on margins, part of the guide down is not all day rates. Some of it’s – we are going to be – it’s going to be a choppier third quarter as we put rigs back to work and things like that. There is going to be some churn and that does affect your cost per day statistics.

Steve Ferazani: Understood. Perfect. Thanks Anthony. Thanks Philip.

Operator: And our next question today comes from Dave Storms with Stonegate Capital Markets. Please go ahead.

Dave Storms: Good morning.

Anthony Gallegos: Good morning.

Dave Storms: Just hoping you could touch on some of the banking issues that you mentioned that we are seeing in the quarter. And it looks like most of them have kind of cleared up. Do you see any potential for any of that to kind of rear its head again, either in the next quarter or further on down the line?

Philip Choyce: Yes. So, what I was referring to was really access to credit on the part of our customers. And you think – and you guys know better than I do. You think back to what was playing out in the second quarter, especially around the regional banking crisis, redeterminations around credit lines and stuff like that, just we think those issues – while they may not be completely resolved, we think they are 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, but as a private E&P operator. And March for a May start, well, May slipped to June, slipped to July. Well, now, we are 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 anecdote that I would share with you guys. But it’s just my understanding and view that I think our customers will have more access to capital, which when 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 around rig 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 break out between the demand for 300 Series rigs versus 200 Series rigs?

Anthony Gallegos: Yes. We are bottomed out in the, I think, 660s where we are right now, maybe it goes to 650. When you look at where the rigs are working in rig count, about half of the rigs are working out in the Permian. We would expect that percentage to continue and even grow. Out in the Permian, there is the Midland Basin work, there is the Delaware Basin work. I think you would expect to see some adds in the Delaware Basin just because of the productivity that you are hearing E&Ps talk about out there. So, what’s important for us is that – and we are not making a call in saying the entire market is going to move to 300 Series specification, but what’s important for us and our stockholders is if that’s where it were to go, we have a very clear pathway towards being able to meet those opportunities or that incremental demand.

Dave Storms: That’s perfect. Thank you for taking my question.

Anthony Gallegos: Yes. Thank you, Dave.

Operator: And our next question today comes from David Marsh with Singular Research. Please go ahead.

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 repurchases. It looks like in the cash flow statement, you spent $5 million exactly the repurchase, but then said par plus crude. So, I just 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: Yes. So, it was $5 million, and the crude interest was probably a couple of hundred thousand dollars on it. 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 then 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 through the end of this year and then it’s $3.5 million each quarter through next year. And this was the first quarter, June 30th. This was the first – this was the first offer that we made, and they accepted it.

David Marsh: Got it. I understand. And then are you guys still picking at this point? And could you kind of update us on plan to possibly transition to cash interest payment on this?

Philip Choyce: Yes. So, I think what we have said publicly is our plan was to pick through March – through March ‘24. Certainly, with the opportunity to cease 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. That’s up to our lenders. Then we probably would – we will be funding the mandatory offers, but we probably would 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 am guessing that the kind of 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 kind of refinancing window under the indenture doesn’t open up until September of next year. Obviously, we are in 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 is probably some better opportunities and discussions we can have next year.

David Marsh: Yes, I would absolutely agree. I just kind of just trying to put a finger on the pulse of it. You guys moved – you guys called out some costs in the press release with regard to moving rigs from 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 – it helps me understand the cost of moving on. So, that’s really helpful. I appreciate it. That’s all I have. Let me yield to someone else here.

Philip Choyce: Thank you, David.

Operator: Thank you. And our next question today comes from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thank you. Good morning. Anthony, as the churn maybe slows down in the Permian basin, do you expect at 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: Yes. I think it’s going to be a little a quarter later than what people may expect, Jeff, and the reason is the rigs laid down. Look, the big players in the business have maintained good discipline in pricing. As there are opportunities presented for people to step into the batter’s box, they are 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 are talking about. So, because of that dynamic, the margin probably lags the uptick in utilization by a quarter. And that’s why we are kind of 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 has 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 it’s probably sooner than people may realize, but it’s going to be a little longer, 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 to the Haynesville if they start to look at the back half of ‘24 and maybe more optimistic view of gas markets then into ‘25?

Anthony Gallegos: Yes, absolutely. Jeff, we have had guys actually have that conversation with us as they are 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. Of course, 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 was Comstock that made an announcement earlier this week and what they are doing in the extreme western edge of the Haynesville, this is a stuff over in Texas and 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 are going to test the deeper Bossier batch 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 are talking big equipment. And there is a limited number of those in the industry, 1 million pound type rigs, big setback capacities, 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 are one of them.

Jeff Robertson: So, that play is migrating towards your rigs in terms of the specifications needed?

Anthony Gallegos: Absolutely, the 300 Series, yes, sir.

Jeff Robertson: Philip, you mentioned that you anticipate that the lenders will accept the redemption offers. So, that really drives or should allow ICD to naturally de-lever 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 on the balance sheet. So, your leverage profile is that refinance window opens up, like you mentioned 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?

Philip Choyce: Yes, I think certainly compared to the guidance that we have provided in the past because I think in the past, we had not really spoken much about them because we didn’t know until – what their plans would be until we saw what they did this quarter. And with them accepting those mandatory offers that certainly accelerates kind of the debt pay-down. It’s beginning now as opposed to really in March of next year.

Jeff Robertson: Thank you very much.

Anthony Gallegos: Thank you, Jeff.

Operator: Thank you. And our next question today comes from John Daniel with Daniel Energy Partners. Please go ahead.

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, ICD, one of them on early term, or on standby, rather.

John Daniel: Okay. But 14 rigs 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 am going to follow-up with – a little add on to his. But I know you mentioned some of the incremental rigs that you are going to deploy likely go to private operators. But I am 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 am curious as your sales guys are getting inquiries from customers, how often are you catching any disconnects where the E&Ps are publicly saying one thing, but they are calling you and asking something else? And obviously, you don’t want to give names, but I am just curious your thoughts.

Anthony Gallegos: Yes. No problem, John. I wouldn’t say it’s a disconnect, I think it’s just more of a perspective into the market. We are not working for any of the super majors today, although we have in the past. And so we are into these discussions, it’s with large independents and especially on the private side. And the opportunities that we are 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 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 are 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 are pursuing and whether or not we think we can get paid for it. So, I wouldn’t say there is as much of a disconnect, it’s just 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 low-70s when times were hopping. Where do you think we hit in ‘24? What would the inquiry suggest we could be at in ‘24?

Anthony Gallegos: Look, if you look at the strip, you listen to what customers say there what price they need to stimulate activity. John, 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 have described a second ago, but just looking at the Haynesville proper that we have all known, I see a dozen pretty easy.

John Daniel: Okay. And I mean, obviously, crap happens if we got 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 knowing it’s still 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: Yes. Awesome. Thank you for very granular answers.

Anthony Gallegos: Yes. Thank you, John.

Operator: [Operator Instructions] Our next question comes from Dick Ryan with Colliers. Please go ahead.

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 lit8tle more commentary on that?

Anthony Gallegos: Yes. Great. And I appreciate you let me talk about that, Dick. We haven’t talked a whole lot about that. Look, like all other industries out there, I mean we have expected the technology and demand 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 have chosen over the last couple of years to not get into the arms race of trying to develop this technology ourselves. Part of that’s 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 mean time, 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, you think about your operating system on your iPhone, you have 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, the requirement 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 where we can create value, not just for our customers, but also for ICD and our stockholders.

So, I guess the point that I am trying to make is that that’s happening now. We have four of these systems deployed. We have 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 have 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 are 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 are somewhere between $500 and $1,500 a day of 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 am really pleased and proud of the third-party partners that we are working with. I appreciate the customer that we have working with us. Like I have said, we just haven’t talked a lot about this over the last couple of years. I didn’t want people to think we are 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 have been able to show year-to-date on this front.

Dick Ryan: Appreciate the color. Thank you.

Anthony Gallegos: Yes. Sure. Thank you, Dick.

Operator: Thank you. Ladies and gentlemen, this concludes your question-and-answer session. I would like to turn the conference back over to the management team for the 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. And with that, we will 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.