Independence Contract Drilling, Inc. (NYSE:ICD) Q3 2023 Earnings Call Transcript

Independence Contract Drilling, Inc. (NYSE:ICD) Q3 2023 Earnings Call Transcript November 1, 2023

Independence Contract Drilling, Inc. beats earnings expectations. Reported EPS is $-0.37, expectations were $-0.51.

Operator: Good morning, and welcome to the Independence Contract Drilling third quarter 2023 financial results conference call. All participants will be in a listen-only mode. [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, thank you for joining us today to discuss ICD’s third-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 much materially from what we talked about today. For complete discussions of these risks, we encourage you to read the company’s release and our documents on filed with the SEC. In addition, we refer to non-GAAP measures starting 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, thank you for joining us for our third-quarter 2023 earnings conference call. During my prepared remarks today, I want to talk about three topics: first, I’ll talk about the super-spec rig market; second, I want to talk about the progress we made on some important strategic initiatives during the third quarter; and lastly, I want to close out talking about our plans as we exit 2023. But first, just a few comments looking back on the third quarter, which was a meaningful quarter for ICD on several fronts. First and foremost, we believe the third quarter represents the low point for ICD operating utilization, as we expect our operating fleet utilization to increase over the next several quarters.

The third quarter also represented the end of the transition of rigs from our Haynesville market to the Permian, and the elevated churn associated with repositioning our work in fleet with customers with longer-term drilling programs. During the quarter, we also saw increased rig inquiries that are leading to rig reactivations during the fourth quarter, and a line of sight for more reactivations in 2024. All of this manifested itself in our third quarter results. Philip will provide more details during his prepared comments, but overall, I see these third quarter results came in at the low end of our prior guidance. Cost per day was impacted by higher labor costs, as we staffed up for known fourth quarter reactivations. We also had slightly lower operating days compared to expectations, driven by rig churn as we prioritized repositioning rigs with customers with longer-term development programs.

During the third quarter, we continued the pursuit of our most important strategic initiative, which is deleveraging our balance sheet by paying down a second $5 million tranche of convertible notes at par. We look forward to continuing to take advantage of these opportunities to pay down debt and we have one more at the end of the fourth quarter and four additional opportunities next year. Equally important to continuing to take advantage of paydown opportunities, is positioning the ICD fleet in a manner that optimizes refinancing opportunities for the convertible debt, when the debt refinancing, when that begins to open approximately 12 months from now. We believe that involves returning to approximately 21 rigs operating, with a higher concentration of 300 Series rigs, working for the right type of customer and stair-stepping our contractual day rates in a manner that maximizes day rate opportunities when we believe market conditions will be stronger.

With that background, I’d like to talk a minute about the market super-spec rigs in our target markets, what we’re seeing from a rig reactivation day rate perspective, and I assume these priorities as we navigate what we expect to see over the next several quarters. As expected, we saw the US land rig count decrease over the third quarter. That was driven by the continued decline of drilling activity in the Haynesville and Permian, softer commodity prices during the summer, and strong capital discipline on the part of E&P companies. For ICD, this resulted in an overall decline in average operating rate rigs during the quarter. But as I mentioned before, we believe the third quarter is the bottom for us. Based upon what we are seeing, our expectation is that overall rig counts in our target markets will improve over the next several quarters.

Some of these opportunities are high-grade efforts on the part of the E&P’s attracted to our 300 series rigs. We expect the Haynesville to remain relatively muted until at least later in 2024. In the near term, I think the impending winter withdrawal season will determine Haynesville activity levels in the first-half of 2024. We also believe rig adds in the near-term are going to be weighted more toward privates, a key customer base for us. From one day rate perspective, in light of the existing softness in US land rig count and the fact that new contracting opportunities have only just began to emerge, we have seen some pressure on day rates. This is more pronounced for incremental rig adds than for renewals with existing customers. And as you might expect, there’s more day rate pressure in the Haynesville that in the Permian.

Day rates for our 300 Series rigs have generally stabilized in the low $30,000 range. And for our 200 Series rigs, the high $20,000 range. But I’d be remiss if I did not mention there are instances where we have lost work to competitors who have gone below these levels. As we get through this initial wave of reactivations, our expectation is that opportunities for day rate improvement will increase, as smaller contractors’ pad optimal fleets are more fully utilized and competition for incremental rig [Technical Difficulty] concentrates within your drilling contractors. We’re also seeing increased demand for our 300 Series rigs, which are principally 100% utilized at this time, which is leading to increased opportunities for our 200 to 300 Series conversion solution.

So what are the near-term priorities that we believe maximize our strategic objectives as we move forward in this expected uptick in activity? We like our fleet to return to 21 operating rigs by the middle of 2024, and we would like to continue increasing the penetration of our 300 Series rigs via our 200 to 300 series conversion, so that at least 75% of our operating rigs earning 300 series day rates by mid-2024. We also want to maintain our Haynesville presence to maximize opportunities there later in 2024 and beyond, when incremental LNG exportation capacity is expected to come online. We believe this setup maximizes ICD’s opportunity to return to margin per day levels that existed prior to the 2023 slowdown. In the near term, as we reactivate rigs, there will be some day rate pressure, thus, we will be looking to sign most of our contracts on shorter-terms, which allow for contract renewals higher rates, when we believe the market will be stronger.

In addition, we want full payback on the initial contract or any reactivation that involves CapEx expenditures associated with our 200 to 300 Series conversion. But how are we doing pursuing these priorities? First, with respect to the Haynesville, I’m very pleased that we now have three of our four rigs there placed with customers’ long-term drilling programs. We have one more 300 Series rigs in the Haynesville that we expect to contract here in the fourth quarter for an early 2024 reactivation. There was a lot of rig churn over the last few quarters to achieve this setup, but we believe that it behind us. Overall, in an environment which we return to 21 operating rigs mid-summer 2024, I’d like to have five operating in the Haynesville, which will be an appropriate balance in terms of commodity and basin exposure for our company, and allows us to leverage our strong brand and reputation for tailoring technology and equipment solutions to exceed our customers’ expectations.

We expect to end 2023 with 17 rigs operating, with another rig likely contracted for an early 2024 reactivation. In this regard, we’ve already signed two contracts for mid-fourth quarter reactivations, entering in advanced discussions for additional reactivations here in the fourth quarter. We also have begun dialogue for additional reactivations mid to late first quarter 2024. But I would consider those more in the early stages of discussion, which makes their outcomes much harder to predict at this time, given the indecisiveness and lack of formal guidance from E&Ps regarding their 2024 upstream CapEx plans. With respect to 200 to 300 Series conversions, we completed two additional 200 to 300 Series conversions during the third quarter, and last week completed an additional conversion supported by a signed contract that more than guarantees full simple payback of the CapEx investments.

With the completion of the most recent conversion last week, we have now converted four of our 200 Series rigs to 300 Series specification. Bigger-picture, this means that about three-quarters of the 17 to 18 rigs we expect to be operating at year-end will be 300 Series rigs, with opportunities to increase that percentage as we move through 2024. This is big for us as these conversions have important strategic implications for ICD, as they provide higher margin potential and additional exposure to the rig market segment with the highest specification requirements for the most technologically demanding work in the industry. By comparison, if you look at the end of the first quarter of this year when we were generating record margins and operated approximately 20 rigs, only half of those rigs were 300 Series rigs.

In addition to the conversions, we are continuing to execute on our rollout of our ICD impact offerings, including technology. We deployed additional systems during the third quarter. And also here in the fourth quarter, including oscillation, stick-slip mitigation, and back to bottom software, EDR packages, and hydropipe systems, and we will have additional rigs operating using the utility grid here in the fourth quarter. We are excited about what ICD impact means for our customers, the environment, and other stakeholders of our company going forward. And I expect the provision of these offerings will continue to enhance our financial performance as I indicated to you during our last earnings call. So rolling all this up, I’m confident that ICD has experienced the worst of the 2023 slowdown.

And we have commenced adding working rigs and repositioning our fleet to maximize utilization and margin potential as market conditions improve. I’ll make some additional concluding remarks before opening the call for questions, but right now, one of 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 $5.2 million or $0.37 per share, and adjusted EBITDA of $12.9 million. In calculating adjusted EBITDA and loss per share, we exclude $1.1 million associated with non-cash SG&A charges during the quarter, associated within a contract modification and extension. We operated 13.4 average rigs during the quarter, slightly below guidance, private provided on our prior conference call, caused by greater than expected idle days between contracts, as we repositioned rigs with customers for longer term drilling programs. During the quarter, we recognized $800,000 of transition costs associated with rig transitions. Early termination revenues during the quarter of $700,000 were recognized and offset partially these costs.

Moving on to our per day statistics, these statistics exclude both the early termination revenues and transition expenses I just mentioned. Revenue per day during the quarter was $32,925, representing a 4.5% sequential decrease from the second quarter. Cost per day during the quarter was $18,900, essentially flat with the second quarter. And overall margin per day was $14,005, on the low end of guidance representing a 9.4% sequential decline compared to the second quarter. SG&A costs were $6.9 million during the quarter, which included approximately $2 million of stock-based and deferred compensation expenses. It also included the $1.1 million charge I previously mentioned. Breaking out the components, cash, SG&A, expenses of $3.8 million were essentially flat compared to the second quarter.

And non-cash base SG&A compensation expense $2 million increased sequentially, driven by variable accounting on awards by the changes in our stock price and full quarter amortization of awards granted during the prior quarter. Interest expense during the quarter aggregated $9.2 million, which included $2.4 million associated with non-cash amortization of deferred issuance costs and debt discounts, which we excluded when presenting adjusted net income. Tax benefits for the quarter were diminimus and in line with guidance. During the quarter, cash payments for capital expenditures, net of disposals were approximately $3.9 million. For the remainder of the year, assuming we move towards 17 rigs reactivated by year-end, we expect capital expenditures during the fourth quarter to aggregate $5.5 million.

This includes cost to complete two additional 200, 300 Series reactivations and purchases of additional strings of drill pipe. Moving on to our balance sheet. So we continue to make progress towards debt reduction goals. We’ve repaid $5 million of convertible notes at par at quarter end and reduce revolver borrowings by $8.5 million during the quarter. The overall reduction and adjusted net debt during the quarter was $8 million. Our financial liquidity at quarter end was $21.7 million, comprised of cash on hand of $6 million and $15.7 million of availability under our revolving credit facility. Now moving on to our fourth quarter guidance, we expect operating days to approximately 1,355 days, representing 14.7 average rigs going revenue during the quarter, with reactivations only partially benefiting the fourth quarter.

We expect margin per day to come in between $11,700 to $12,300, with sequential decline related to lower day rates on contract renewals, slightly higher cost per day level, this contract mix becomes more heavily weighted towards the Permian Basin. Breaking out the components, we expect revenue per day to range between $31,000 and $31,500. We also expect sequential cost efficiencies during the quarter associated with contract reactivations, with the cost per day expected to range between $19,200 to $19,600 per day. I think it’s important to point out that only 4.5% of our expected fourth quarter revenue will be generated from legacy contracts executed in 2022. Plus, we believe the fourth quarter provides a reasonable estimation of the current spot day rate environment during the initial stages for the expected recovery in US land rig count.

Given only three of our current rig contracts extend past the first quarter of next year and then beyond the second quarter of next year, we believe we have positioned ICD to participate in a day rate recovery, driven by expected growth in the US rig count of the third quarter bottoms. Unabsorbed overhead expenses are expected to be about $600,000. We’ve excluded those expenses from our cost per day guidance. We do expect to incur rig reactivation expenses during the fourth quarter associated with the rehiring crew and the replenishment of operating supplies for the rig additions to our operating fleet during the fourth quarter and early 2024. Overall, we expect these will aggregate approximately $1 million during the quarter and are excluded from a margin per day guidance.

We expect fourth quarter cash SG&A expense to be approximately $4 million. Stock based compensation expense should approximate $2 million, assuming no material changes to our stock price that would impact variable accounting on awards. We expect interest expense to be approximately $9.7 million. Of this amount, approximately $2.6 million will relate to non-cash amortization of the deferred financing costs and debt discounts. Depreciation expense for the fourth quarter is expected to be flat with the third quarter, and we expect tax benefits to be diminimus during the fourth quarter. And with that, I’ll turn the call back over to Anthony.

Anthony Gallegos: Thanks, Philip. So wrapping all of this up, we believe ICD is very well positioned as we exit this most recent slowdown. In fact, I feel this is the strongest ICD there have ever been when entering an expected upturn in drilling activity. We continue to make progress on the three most important strategic initiatives we had, which include paying down debt, increasing our exposure to the 300 series market, and leveraging our ICD impact offerings. We remain optimistic about market momentum strengthening as we spread to year end 2023, primarily in all directed markets based on recently increased commodity prices during customer inquiries and discussions we’re having, and our expectation that WTI pricing will remain higher than the levels we saw during the second, third quarters of 2023.

I also think the effects of depleted duck inventories and more cash flow for our customers will provide additional boost to demand for drilling rigs in our target markets during 2024 from recharged E&P capital budget next year. For these reasons, I’m optimistic about reactivating our remaining idle rigs, on our way back to 21 operating rigs over the coming quarters. With that, we’ll open up the call for questions.

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Q&A Session

Operator: [Operator Instructions]. We will now begin the question-and-answer session. First question today comes from Don Crist with Johnson Rice.

Don Crist: Morning guys. Anthony, obviously, you walk through the demand picture out there, but can we get a little bit more color on particularly in the Haynesville? Obviously, you had a bunch of rigs running their early part of last year and then it fell off fairly significantly. And I think, if I heard you correctly, that you’re expecting to be five rigs again back in that area. Can you just expand on that a little bit and just the overall demand picture color?

Anthony Gallegos: Sure, Dan. Thanks for the question. You’re right. A lot of what happened to ICD this year was a function of our market presence in the Haynesville at the beginning of the year. And to put it into perspective, we had half our fleet contracted, just 10 rigs, working in Haynesville. Half of that 10 was with one customer who went from five rigs to zero. So that played out for us over the second and the third quarter, we bottomed out at to two rigs operating in over there, three rigs contracted. As commodity prices and rehab has improved as some of the local takeaway issues have been addressed, there’s been a small amount of demand appear. Some of it’s been in the western part of the Haynesville, the stuff over and Leon and Robertson County.

I think we heard an operator talk about that earlier this week; fantastic results they were reporting for their sixth and seventh wells, that’s good for our industry. For us, a prior customer of ours has started back up. We were their first call, that rig is back up and running now. It’s exciting for us as a company because we have started talking a lot about technology, so they picked up a sister rig to a rig they had before. This time, we have our technology, the technology that’s coming from third party partners that we have deployed and they’re seeing amazing results: better ROP, the same or better whole quality stuff like that. In addition to that, as we’re approaching fourth quarter, we expect to have the fourth rig contracted and running as we round out next year.

So just to put it in perspective, that means that the four rigs that we still have in base and all four will be contracted by the end of the year. We don’t have that for contract signed, but I’m pretty confident is going to come. When I mentioned five, that’s looking out into next year. Obviously, it would require that we move a rig back. We’re only going to do that if the conditions around the contractor are better than what we think we can do in the Permian. But as we think about that market longer term, from an ICD status quo perspective, five would be the top out of the 2021 that we would expect to be running in the back part of next year. Rates are softer. I mentioned that in the comments, when you think about the two markets. Haynesville, rates are a bit softer and that’s just a function of having gone from 80 rigs in the basin work into 38, 39 today.

Hasn’t been a lot of capacity move out, we’d probably move more about than anyone, still a lot of capacity on the sidelines. So we would expect pricing in the Haynesville to remain more challenging than the Permian, even against the backdrop of recharge budgets, capital budgets for 2024. But we’re very bullish in the long-term. I think in the short term, winter is going to be very, very important to what happens to gas prices. But our conversation with E&P customers in the Haynesville, there’s a lot of bullishness around the back part of 2024, especially 2025 and beyond, and that’s being driven by the expectations around LNG exports. So it’s a great market for us. It’s one of our two core markets. Strong brand and reputation over there, certainly don’t want to abandon that market.

I think it’s a place where we can really bring our talents to bear. And not just compete with everybody but outperform them as welI. But that’s what I would say about the Haynesville market, Don.

Don Crist: All right, I appreciate that color. And to talk a little bit — or to touch on the conversions, I’m assuming that it’s contracts that are pulling forward those conversions that you’re not just doing those on spec. And can you remind us of the of the day rate uplift that you get when converting a Series 200 to a 300?

Anthony Gallegos: Yes, you’re correct. We are doing those against a contract that is going to guarantee us simple payback, cash-on-cash. Obviously, we want to make a return on that, too. But just given the volatility, cyclicality of the business, it’s very, very important that at a minimum, we get that cash back. What we’ve said in the past and it’s holding out to be true, is it’s $2,000 to $3,000 a day uplift is what we see. It is interesting to me also because of the four conversions that we’ve completed so far, and we did two in the third quarter and we just finished another one; in fact, that rig started moving yesterday. But three of the four have been with customers that had the 200 series rig running first. Great rig.

And I am always concerned when I talk about our 300 that are somehow casting the 200 in about a lot of knot. They are super-spec pad optimal rigs, they go toe-to-toe with everything that’s out there. But the reason I point this out is three of the four have gone to customers that used to 200 Series rigs. They were very, very pleased with the 200 Series rigs and they like the fact that we can give them a little bit more capability with the 300 Series conversion. And we’ve been able to sign contracts that meet our requirements in terms as of the cash-on-cash payback.

Don Crist: Okay. And just one final one for me. Can you remind us what the current conversion prices? It’s a couple hundred thousand, right?

Philip Choyce: So it’s $650,000 to $800,000.

Don Crist: Okay. But you’re getting cash-on-cash payback over the contract term on those, right?

Philip Choyce: Yes.

Anthony Gallegos: Yes.

Don Crist: Okay, I appreciate it. I’ll get back in queue. Thanks.

Anthony Gallegos: Great. Thank you, Don.

Operator: Next question today comes from Steve Ferazani with Sidoti

Steve Ferazani: Good afternoon, everyone. Appreciate the detail on the call. I just want to do a lot of numbers; I just want to connect some of the dots. Based on your guidance, how many rigs do you have drilling at the end of 3Q? And how much do you have how many rigs are drilling right now?