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Edited Transcript of ICD earnings conference call or presentation 28-Feb-20 3:00pm GMT

Q4 2019 Independence Contract Drilling Inc Earnings Call

Houston Mar 24, 2020 (Thomson StreetEvents) -- Edited Transcript of Independence Contract Drilling Inc earnings conference call or presentation Friday, February 28, 2020 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* John Anthony Gallegos

Independence Contract Drilling, Inc. - Director, President & CEO

* Philip A. Choyce

Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary

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Conference Call Participants

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* Daniel Joseph Burke

Johnson Rice & Company, L.L.C., Research Division - Senior Analyst

* Kurt Kevin Hallead

RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst

* Ryan James Pfingst

B. Riley FBR, Inc., Research Division - Associate

* Taylor Zurcher

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research

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Presentation

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Operator [1]

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Good day and welcome to the Independence Contract Drilling, Inc. Fourth Quarter and Year-End 2019 Financial Results Conference Call. (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.

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [2]

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Good morning, everyone, and thank you for joining us today to discuss ICD's fourth quarter and year-end 2019 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 loss to adjusted net 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.

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [3]

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Thank you. As typical, Philip will go through the details of our results for the fourth quarter of 2019 and 2020 guidance. In my prepared remarks, I will be focusing on where we see the land drilling market, ICD's strategy and positioning in this market and the key initiatives we have underway in this regard. And finally, talk about near-term market activity as we continue to navigate the current market conditions and recent uncertainty caused by the corona concerns.

As we highlighted on our previous conference call, 2019 was a pivotal year for ICD as we readjusted and recalibrated to what we believe is the new normal. Oil prices generally range bound between $50 and $70 a barrel, U.S. land rig counts typically range bound between 800 and 1,000 rigs, which, of course, we're below that right now. And mindsets and priorities of our E&P customer base and the contract drilling industry shifting from growth in production, or contracted rig count as the case may be to generating free cash flow and returns.

In this new normal, there's limited access to growth capital made available from financial markets, efficiency and cost control are prioritized over growth, and our customers are laser-focused on maximizing drilling efficiencies and require the most modern and efficient contract drilling services in order to prosper. For the contract drilling industry, we believe this means the final manifestation of the rig replacement cycle.

Since the fall of 2018, we have seen the U.S. land rig count fall over 300 rigs, and we have seen the AC market share increase by over 10% in the short time. And we are faced with some near-term coronavirus issues I will discuss in a moment that has the potential to further accelerate these trends. We believe any legacy equipment and even some lesser specification AC rigs laid down in this current recent rig count adjustment will never return to operation. And if a rig was laid down in 2015 and did not return to operation during the most recent uptick in activity in 2018, we believe it's obvious that rig will never return to work in the U.S. land market. The capital required to reactivate or upgrade such rigs is simply not available nor will it make economic sense in environments such as these.

Now against this backdrop, 2019 was extremely important for ICD as we significantly strengthened our competitive and fiscal position in order to deal with this new world order. We successfully completed the Sidewinder integration, eliminating over $15 million in duplicative SG&A and operating costs and have in place scalable, robust financial and operating systems, including industry-leading HS&E and people development processes preferred by our target customers.

In addition, we've built the operating scale to run a much larger rig fleet within our target markets. The main point being we knew that consolidation reduces redundant cost, and we demonstrated that. Furthermore, scale offers operational benefits to our customers and in the new normal, we believe further consolidation of pad-optimal fleets in our industry is an economic necessity in order to maximize operating efficiencies internally.

We can't predict when further consolidation will happen. There are structural challenges that must be overcome, and, of course, social challenges bring wrinkles and uncertainties. But ICD is a willing consolidation participant with a demonstrated capability. And we are extremely well positioned with institutional knowledge, supported by robust systems and processes underlying a proven track record of successfully integrating competitors and in the process unleashing substantial value creation opportunities for our shareholders, our employees and our customers.

In 2019, we also significantly enhanced our competitive position vis-à-vis drilling optimization technology. This area is in the very early stages, and it still remains to be seen where it leads our industry, but ICD is very well positioned in this regard. We've taken prudent steps and established partnerships with multiple third parties in order to outfit our rigs with the latest technology.

As promised, we deployed systems last year not just on 1 rig, but on 3 of our rigs during the fourth quarter. And as evidence of our momentum regarding these initiatives, we were recently awarded additional contracts in the Permian with a major operator based partly upon our capabilities in this regard. The important point being, ICD has a history of helping drive the technological evolution of drilling rig technology since our inception in 2011. And those efforts continue today.

ICD is competing in this evolving market, and we have solutions in place that create value for our customers, which should provide additional operating margin eventually. And which are scalable across our existing drilling fleet and with any other rig fleet that we may come down through further consolidation. Now as we look into 2020 and beyond, this new normal has also required ICD take hard sober look at our drilling fleet following completion of the Sidewinder integration and reconfirm our strategy to maximize returns. As a result of this review, during the fourth quarter, we recorded an impairment charge of approximately $26 million during the quarter relating to rigs and equipment that will be scrapped or sold.

This equipment primarily relates to old legacy equipment acquired in the Sidewinder merger, that does include 2 AC rigs, also acquired in the merger that have not operated for over 5 years, which were never included in our marketed fleet and which will be sold in an orderly liquidation. These rigs require significant upgrade CapEx to reactivate, and we do not believe they will operate in our target markets in the foreseeable future.

In connection with this exercise, we reclassified, after impairment, $5.6 million of assets at year-end to held for sale. In the near term, we will expend energy and efforts on a highly focused, well equipped, very marketable fleet of 29 rigs. Excluded from this marketed fleet are several rigs that are relevant in the current environment but require modest additional upgrade CapEx. Completion of these projects is being deferred until market conditions warrant, meaning higher dayrates and longer-term contracts for our working fleet and sustainable market conditions.

These rigs will not reenter our marketed fleet until that time. In the meantime, we want to drive margin improvement and higher and steadier utilization with our marketed fleet. On the ESG front, ICD has been talking about the bi-fuel capabilities of its ShaleDriller fleet for years and with the ESG issues, now moving to the forefront, this becomes even more important.

Today, all of our rigs are bi-fuel or highline power capable and approximately half of our rigs operating today are actually utilizing the rig's bi-fuel capabilities, and we expect that utilization rate to continue to increase.

Regarding CapEx, we have rightsized that as well, which means we've made a significant reduction to historical levels of CapEx spend at ICD. To support our marketed fleet, our capital budget for 2020 has been set at $10.2 million, of which approximately $8 million relates to maintenance CapEx and the remaining to discrete equipment additions to our marketed fleet, including adding third mud pumps and fourth engines as our customers require. Following the planned additions of such equipment during the first half of this year, which is already in motion as we speak, approximately 75% of our operating rigs will be outfitted with third pumps and/or fourth engines.

I want to point out that this budget is flexible and was approved before coronavirus concern surfaced. If market conditions deteriorate, we will adjust our capital expenditures accordingly.

Moving on to our rig count progression and near-term market conditions. As discussed on our last conference call, we expected ICD's contracted rig count to improve and transitional issues to subside during the fourth quarter of 2019 and into the first quarter of 2020 based upon inquiries, discussions and contract negotiations, which were taking place principally in the Permian Basin. And for the most part, that's held true.

During the fourth quarter, we signed 16 new contracts or contract extensions and went to work with 3 new customers in the process and expanded our operating rig count in the Permian. Overall, we exited 2019 with 21 rigs under contract working in 3 different basins, including the Permian, Eagle Ford Gulf Coast and the Haynesville.

On the other hand, during the fourth quarter, we had 6 rigs or almost 1/4 of our operating rig count, operating in the Haynesville, where our 2 largest customers have elected to reduce their drilling programs and allocate a larger percentage of the CapEx budgets to completion activity in light of sub $2 natural gas prices.

Fortunately, our rigs operating in the Haynesville have provided some of the most safe, efficient operations in one of the most challenging environments in the Lower 48. In fact, these rigs have worked for the most part continuously even through the 2016 downturn. Thus, we have had success remarketing and recontracting these rigs so far, but we are still dealing with a couple.

In the first quarter so far, we've signed 5 new contracts, including 2 extensions, and we're negotiating a fifth contract, which will be a new customer as we speak. So as you can see, we've been very busy on the contracting front. We currently have 22 rigs under contract at the time of this call, and there are 3 rigs in our marketed fleet where we are actively working on near-term opportunities for what would be incremental contracted rigs, meaning reactivations over the next 60 to 75 days.

Having said all of that, although we expect to exit the first quarter with at least 22 rigs under contract, developing coronavirus concerns over the last 2 weeks makes forward visibility extremely difficult.

Just this week, before this call, we signed several contract extensions and a new contract. We also had one customer this week tell us they are reducing their drilling program in light of commodity price changes, meaning a rig potentially coming back to us that we otherwise were not expecting. It's simply too early to tell what impact the virus will have on market dynamics and our operating fleet. But if oil prices remain below $50 a barrel for a while, we would expect the U.S. land rig count to decline, and we will adjust our operations accordingly.

So with that, I want to discuss ICD's financial position and how we plan to handle any market softness associated with the coronavirus. First, we have reviewed and continue to review our supply chain to make sure products we purchase to operate our rigs are not at significant risk. The vast majority of our key equipment items are manufactured and purchased domestically, but we continue to keep an eye on consumable inventory items that potentially could be affected.

From a balance sheet perspective, we do not have a debt maturity until October of 2023 and had financial liquidity of $45 million available to us at year-end comprised of cash and availability under our undrawn revolver and committed term loan accordion.

Even before coronavirus issues surfaced, we already had undertaken efforts to reduce our support-related costs by an additional $1 million on an annualized basis starting early second quarter.

In addition, our capital budget is principally focused on maintenance CapEx and is scalable to activity levels as is the vast majority of our operating support cost and a portion of our SG&A budget.

Moving on to dayrates. The dayrate environment has remained relatively stable with respect to contract renewals, but we have seen some dayrate pressure when competing for new opportunities, including in the Haynesville, where rig utilization is under greater pressure today.

Right now for us, even on contract renewals and signings, this week in face of coronavirus uncertainty, leading-edge revenue per day net of pass-throughs in the 20-ish range on renewals and in the high teens, where competition is greatest.

Contract tenors are predominantly pad to pad today with some near-term opportunities in the 6-month range. Thus I don't see our reported backlog metrics improving substantially in the near term.

On the cost side, Philip will go through the details, but our reported fourth quarter cost per day included costs, which were anticipated associated with repositioning of rigs, but also included higher-than-expected R&M expense, which we do not expect will continue.

Summing all this up, I believe, ICD is extremely well positioned to deal with any market headwinds that develop due to coronavirus matters, and more importantly, is very well positioned strategically in the U.S. land drilling market that we see existing for the foreseeable future.

Our rig technology initiatives are gaining momentum, and we have rightsized our marketed fleet, support organization and capital budgets to maximize cash flow in the near term and can make further adjustments in the event there are near-term market headwinds.

I also want to highlight that the largest portion of our annual incentive compensation and long-term incentive programs are now directly aligned with these same goals. Our rig fleet is young, it's engineered to maximize manufacturing efficiencies for our customers. Our rigs are drilling optimization capable and are already existing our industry and customers' efforts to address ESG concerns and mandates.

Our merger integration is complete. We are enjoying substantially more from our cost, vendor and customer synergy opportunities resulting from the merger. And we are ready to participate when consolidation opportunities with appropriate industrial fit and economic rationale present themselves. We remain focused on North America's most prolific oil and gas-producing regions, which reside in Texas and the contiguous States.

With that, I'll turn the call back over to Philip, so he can walk us through the financial results for the company.

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [4]

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Thanks, Anthony. During the quarter, we reported an adjusted net loss of $35 million or $0.47 per share and adjusted EBITDA of $7.2 million. Included in calculating adjusted net loss was a noncash impairment of $25.9 million associated with the write-down of equipment we intend to scrap or sell. Adjusted net loss and adjusted EBITDA both include a charge of approximately $500,000 or $0.01 per share related to collectibility of an accounts receivable associated with the premerger contract.

With respect to other items during the quarter, reported revenue per day was $20,241, consistent with quarterly guidance and representing a sequential decline of $318 per day.

Rig utilization of 77% increased sequentially but came in slightly below guidance provided on our third quarter conference call, primarily due to a delay in scheduled rig reactivations in the Permian during the quarter as well as Haynesville transition issues Anthony discussed in his prepared remarks. Cost per day of $14,707 was negatively impacted by expected rig transition costs. Overall costs per day came in higher than guidance, principally due to higher R&M expense during the quarter, which we do not expect to continue.

SG&A costs of $4.7 million, including noncash compensation expense of approximately $500,000 came in higher than guidance, with the difference principally relating to the accounts receivable reserve I previously mentioned. Depreciation and interest expense came in consistent with our prior guidance. We recorded a tax benefit for the quarter of approximately $700,000 related to an adjustment to deferred Louisiana state tax accruals. Overall tax expense for the year was de minimis. Cash payments for capital expenditures, net of disposals and insurance recoveries were $2.2 million during the quarter.

Moving on to our balance sheet. At December 31, we reported net debt, excluding finance leases and net of deferred financing costs of $122.3 million. This net debt is entirely comprised of our term loan, which requires no amortization and does not mature until October 2023. The facility is prepayable at any time and contains minimal financial covenants. Finance leases reflected on our balance sheet, for accounting purposes, did increase at quarter end, is related to retooling of our leased vehicle fleet with new vehicles replacing depreciated lease vehicles and timing of a few equipment upgrade purchases.

At December 31, we had total liquidity of $45.3 million, comprised of cash on hand and availability under our undrawn revolver and term loan accordion. Our backlog at December 31 stood at $51.5 million, representing approximately 6 years of work -- of rig years of work, all of which expires in 2020.

This reported backlog includes rigs under contracts with original terms of 6 months or greater, thus, rigs operating under short-term contracts and principally pad-to-pad contracts are not included in this reported backlog.

Now moving on to guidance for fiscal 2020 and the first quarter of 2020. For annual guidance, we expect depreciation expense to be approximately $48 million for the year, we expect interest expense to approximate $14.5 million, including $1 million of noncash interest expense. We expect SG&A expenses, excluding stock-based compensation to approximate $14 million, and we expect stock-based compensation to range between $2.5 million and $3 million. This SG&A budget is predicated on current activity levels and will be adjusted if market conditions deteriorate.

As Anthony mentioned, our capital budget for 2020 is $10.2 million, but that, too, is predicated on maintaining current activity levels. Other nonoperating items affecting our cash flows in 2020 will be finance lease payments of $2.5 million and a final payment of Sidewinder merger consideration of approximately $3 million associated with the sale of 11 mechanical rigs and associated equipment owned by the legacy company. At December 31, 2019, we also had assets classified as held for sale that we intend to sell over the next 12 months.

Moving on to guidance for the first quarter of 2020. As Anthony discussed, we are transitioning rigs from the Haynesville to other operating regions in response to changing market conditions. This will impact first quarter utilization and cost per day metrics. With this backdrop, we expect our average operating rigs during the quarter to be around 19.3 rigs with revenue days ranging between 1,750 and 1,760 days. As Anthony mentioned, we currently have 22 rigs under contract and line of sight on a couple other potential contracts. Thus our first quarter exit rate will exceed our average rigs operating during the first quarter.

However, as Anthony mentioned, forward visibility is very limited based upon current developments. We expect recorded revenue per day to be around $19,500 to $19,700 during the first quarter.

On costs, we expect cost per day during the first quarter will be lower than the fourth quarter of 2019, but still higher than the normalized run rate. A small amount due to normal seasonal payroll matters, but more significantly by the transition of rigs from the Haynesville. We expect first quarter costs to range between $14,000 and $14,300 per day during the quarter.

First quarter SG&A expense is expected to be $4.3 million, including $600,000 of stock-based compensation, higher than annual average due to seasonal year-end audit and reporting costs. Depreciation expense should be relatively flat to the fourth quarter as most of our impairment charges related to equipment acquired in the Sidewinder merger that had never been placed in service by ICD. And interest expense during the first quarter should approximate $3.6 million and tax expense should be approximately $200,000.

On the balance sheet front, we are forecasting a modest first quarter working capital investment due to seasonal first quarter payments. As Anthony mentioned, our planned third pump, fourth engine upgrades are somewhat front-loaded to the first half of the year. Planned asset sales, obviously, have the potential to offset this. The timing of these items is difficult to predict. And with that, I will turn the call back over to Anthony.

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [5]

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Thanks, Phil. I have no further comments at this time. Operator, let's go ahead and open up the line for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question today will come from Kurt Hallead with RBC.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [2]

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Tricky times, indeed, right? So Anthony, you did give a great summary in terms of operation and preparation for future uncertainties here. One thing that kind of caught my attention, though, was the commentary you made about you had one of your E&P customers come back and tell you effectively that they're going to be reducing their overall rig count. Just want to get a general sense from you on that is, you think that's a one-off kind of dynamic? Or do you think that's kind of a canary in the coal mine?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [3]

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Yes, we don't really know, Kurt. First, thanks for the question. That call literally came in late in the week. It's been a pretty productive week for us, just to put things into perspective, had successfully negotiated and executed some contract extensions and even a new contract for a rig to go up. So not real sure how to gauge it. You never know until the end of the discussion or the negotiation with the customer, what he ultimately is going to do.

I just felt that, obviously, having that information in hand, walking into the call I should at least let people know. So not real sure exactly what that means. Obviously, we're in discussions with them now, and we'll work through that over the next couple of weeks. So sorry, I just can't give you any more visibility beyond that because I don't know, Kurt. But it is the first one and the only one that we're aware of that is contemplating adjusting their drilling schedules at this time.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [4]

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Yes, and I appreciate your candor. So I think the other dynamic I wanted to explore a little bit, is you mentioned, you got the software packages on kind of 3-year rigs? And then you talked about the dynamics around bi-fuel rig capability. So maybe first on the software packages on the 3 rigs that are operating. Can you give us some general sense as to what the revenue model is for that?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [5]

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Yes, we're working through that right now. First, I'm really excited about what we have to offer the industry. We've been talking about this now for a couple of quarters. It's playing out amongst our competitors as well. I believe we've teamed up with some really smart companies, with some really smart people that have some great technology. And have been working on this for years.

For us, it's really, really important that we manage the situation. I think what's lacking today is customer conviction. There's curiosity, certainly, interest is higher today than it was a year ago. But I still think there's a lot of wait and see. So from a pricing standpoint, the strategy that we've employed really is getting the technology out, getting it -- putting it in use. I think the value creation that -- that's there will be obvious. More worried about proving up the technology, demonstrating its capability to our customers than getting paid.

I think -- as I think out further, Kurt, obviously, I think there are some cost reductions and support cost out at the rig site that our customers will be able to enjoy through the use of the technology. And then also, obviously, there's going to be efficiencies that will show themselves in better rates of penetration and things like that, reducing cycle times, ultimately reducing cost to drill the well. So it's a TBD at this time. Different people have different opinions about it. I do think there's value to be created. Obviously, we wouldn't do it. And I think there's going to be value that's going to accrue to ICD. But we've taken a very prudent approach toward it, paying attention to what we're investing on the front end. And that's how we're going to proceed.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [6]

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And maybe just -- and maybe on the bi-fuel element, what kind of demand pull are you seeing? Is there an acceleration in interest in using bi-fuel rigs?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [7]

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Yes, there is. It's also highline power, too. Kurt, it's really interesting to me. I was out in Midland, 2 weeks ago, saw almost a dozen customers. I was surprised when I talked to them about their focus for 2020 to learn that almost every one of them mentioned ESG and addressing ESG.

Our rigs are bi-fuel capable. A year ago, fewer of them than today were using the bi-fuel capability, but we've certainly seen an uptick in that use. And then more recently, the discussion surrounding the use of highline power has picked up pretty significantly. So much so that I would expect, certainly within the second quarter, ICD will have at least one rig running on highline power and I would expect to see the increased use of bi-fuel capability on the rigs that we have.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [8]

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And does that translate to a higher cash margin?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [9]

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Well, it should. There's R&M expense associated with the generators. So you would expect that. But because of -- out in the Permian Basin especially, not all of the areas can provide the same level of electricity and reliability. So the generators still have to be there. Depending on latency, redundancy of those power systems, you may run the generators more on one location than you might on another.

So it's just one more thing that we're going to have to feel our way through. Costs certainly aren't going to go up for ICD. If anything, you would expect them to go down. But very importantly, the industry is continuing to do what it can to try and address the ESG concerns that are out there.

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Operator [10]

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Our next question will come from Ryan Pfingst with B. Riley FBR.

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Ryan James Pfingst, B. Riley FBR, Inc., Research Division - Associate [11]

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In the second quarter, you guys moved a rig to the Eagle Ford. Do you see more opportunities there? Or is the Permian really the focus as you move some rigs out of the Haynesville?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [12]

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Yes. As we look across, obviously, the Haynesville is the softest, Ryan. Permian is the strongest in terms of adding rigs. I would rank the Eagle Ford as second, in terms of rigs going back to work. We are working on an opportunity down there even as we speak. So I do expect certainly in the first half of the year to see incremental rigs go to work F=for the industry in the Eagle Ford. Not as many as the Permian, but I would expect to see a pickup down there.

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Ryan James Pfingst, B. Riley FBR, Inc., Research Division - Associate [13]

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Got you. And we're still over 3 years away from your earliest debt maturity, but can you expand on how flexible your debt is in terms of the ability to restructure or renegotiate terms if that becomes necessary as we march towards 2023?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [14]

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Well, you know our term loan holder is also our largest stockholder. So it's not a -- it's a phone call away if we think we need to do something like that. Obviously, it's 3 years away from a -- terms of the current facility. It's got minimal financial covenants that really don't come into play. It's a minimum liquidity covenant of $10 million, and we're not really near anything like that right now.

So -- and it's prepayable at any point in time. So we'll have to address those things as we get closer down -- closer there, but it's not a drawn-out negotiation. It's a phone call.

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Ryan James Pfingst, B. Riley FBR, Inc., Research Division - Associate [15]

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And then maybe just one more following up on the drilling optimization technology. Do you have any idea how and -- or can you explain how and when that technology becomes additive to your margins?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [16]

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Yes, I would -- Ryan, I would think sometime this year, it would be additive. The approach that we've taken really is based upon the amount of CapEx that we invest on the front end versus our partner. The CapEx that we have to invest is minimal, especially considering the value of the rig, but that's the approach that we've taken.

Look, I think there's value to be had. I do think, eventually that that will accrue to the contractor. Right now, our customers are just hyper-focused on cost mitigation, reducing cost. They're not incentivized to take a lot of risk even when the value may be large on their part. But I would certainly expect and hope that sometime during this year, we're in a situation where we are able to see that begin to flow to the bottom line.

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Operator [17]

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Our next question will come from Daniel Burke with Johnson Rice.

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Daniel Joseph Burke, Johnson Rice & Company, L.L.C., Research Division - Senior Analyst [18]

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Let's see. So I recognize the industry rig count overall is risked as we sit below $50 WTI. But just in regards to the Haynesville, can you maybe just summarize what you've been able to achieve, the stability you see there with remaining rigs? Has that transitional period sort of concluded? Or what level of lingering risk do you have from ongoing Haynesville exposure?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [19]

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Yes. So just my read, Daniel, in what's happening is activity held up better in the Haynesville last year than I think a lot of people thought. I believe what happened is as our customers rounded out the year, hedges began to roll off. They then became exposed to market prices, which, as you know, were below $2 an Mcf. They had to recalibrate budgets. And we had 2 large customers over there, just to put it into perspective, ICD back in November had 6 rigs contracted in the Haynesville were 3 today. Both of those customers decided to reduce their CapEx budgets for 2020 but also reallocate the percentage of spend toward completions.

In other words, it was a change compared to 2019. And that's what precipitated the reduction in rig count, at least on the ICD side. We've been very quick to recontract a couple of those.

In fact, one of them has already moved out to the Permian and has been on contract now here in -- during February. And the second one, we're nearing completion of the contract that will also require we move that rig out west as well.

So for ICD, we've got a couple more to worry about, and we're working on those. We have a little bit more time here before we know for certain what happens with those rigs. But it feels like we're nearing stabilization for ICD in the Haynesville market.

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Daniel Joseph Burke, Johnson Rice & Company, L.L.C., Research Division - Senior Analyst [20]

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Okay, great. And then a follow-up. The held-for-sale account, $9 million held for sale. That could be a meaningful component to sort of this year's cash flow outlook. Can you talk about the -- what's in that bucket? What's the ease of selling that stuff? Is that easily auctionable equipment? Or is that -- some of that likely to linger for some time?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [21]

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Yes. So there's a couple things to think about there. The way that's valued is at a fair value for accounting purposes, which is a 2-year orderly liquidation, kind of how they look at it, what we would expect to get. We'll have to wait and see how quickly we sell it, Daniel. There's a couple million of it that really gets to go to the former Sidewinder shareholders, so that's really not to -- going to come to our account. And so you're really remaining with about $5 million -- say, $5 million in there.

And as Anthony talked about, it's some legacy SCR rigs that we've never really talked about, 1,000 horsepower rigs. There's a small, 1,000 horsepower AC rig that's never operated since 2014 that we've really never talked about that was in the Sidewinder assets. And there's one older-generation AC rig that's in there as well.

I would -- we're going to try -- we're marketing those today. I would expect kind of a steady flow, but it's going to be -- it's hard to predict when that's going to happen. I'd like to think that we can monetize half of that this year.

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Operator [22]

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Our next question will come from Taylor Zurcher with Tudor, Pickering and Holt.

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Taylor Zurcher, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research [23]

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Phil, on the cost side, you talked about some near-term churn in the Haynesville rig count was going to keep costs elevated. But as we think over the balance of the year, in the past, you've talked about 13.5 as being kind of the normalized level. Is that a level you think you can get to towards the back half of 2020?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [24]

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Yes, as long as everything stays stable, that's what all our projections are. What we're talking about on the transition cost for the rigs in the Haynesville. Typically, we're not paying for the transportation costs. But you do have a -- we're going to pay for the crew transition costs between the time that the rigs go off contract to the time that they start drilling again in the Permian. That's really the transition costs we're talking about. So I think we feel pretty good about that number. If there's any softness in the rig count, then that can make that -- we'll have to address that.

But assuming we're running 22-plus rigs for the remainder of the year, we feel pretty good about this -- getting back to a normalized rate.

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Taylor Zurcher, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research [25]

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Okay, got it. And then just from a pricing perspective, I realize there's a bit of a delta between renewals and some incremental or new customer opportunities. But within that subset, you talked about high 20 -- or excuse me, 20-ish for renewals and high teens for some of these newer customer opportunities. Is there any delta within that between some of your 200 Series rigs and 300 Series rigs? Or does it really follow the bifurcation that you talked about in prepared remarks?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [26]

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Yes. Really, the delta, Taylor, would be tied to rigs that have third pumps -- mud pumps and then four generators. Also the delta is tied to where we're negotiating with an existing customer. And it's a rollover situation versus an incremental rig requirement for a customer we're not working for today, just the competition is pretty intense. There's a lot of good equipment that's available today, as you know, and people want to win those jobs. So that bifurcation really is based upon the outfitting of the rig, the gins and the pumps. And whether or not it's an incremental opportunity for a customer you're not working for today.

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Taylor Zurcher, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research [27]

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Okay. You're guiding to basically a high $19,000 a day number for Q1. If the fleet kind of marks the market, and we don't see any pricing deterioration from here, is that $19,500 to $19,700 number you guided to biased lower over the back half of the year as the fleet marks to market? Or are you kind of near the bottom?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [28]

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So one way to think about that is how many rigs in backlog do we have that are kind of higher. We negotiate -- our contracts last year, there's a couple. There's not a lot. Most of our fleet has been recontracted to the new rate. So there's going to be a slight bias downward, but it's not -- we're not operating under a bunch of legacy contracts that haven't repriced in the last 3 to 6 months.

We have 2, I believe, in our backlog today that we're operating under. So there'll be a slight -- I think there's a slight bias downward, but not significant.

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Operator [29]

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This will conclude our question-and-answer session. I would like to turn the conference back over to Mr. Anthony Gallegos for any closing remarks.

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [30]

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Okay. Great, guys. We appreciate everyone taking the time to dial in and participate in today's call. We look forward to seeing you out on the road. I do wish everyone a safe and nice weekend. We'll end the call now. Thank you.

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Operator [31]

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The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.