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Edited Transcript of ICD earnings conference call or presentation 7-May-20 4:00pm GMT

Q1 2020 Independence Contract Drilling Inc Earnings Call

Houston Jun 3, 2020 (Thomson StreetEvents) -- Edited Transcript of Independence Contract Drilling Inc earnings conference call or presentation Thursday, May 7, 2020 at 4:00:00pm 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 First Quarter 2020 Conference Call. (Operator Instructions)

Please note that this event is being recorded. I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer of Independence Contract Drilling. Please go ahead, sir.

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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 First Quarter 2020 Results.

With me today is Anthony Gallegos, our President and Chief Executive Officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for a full reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures.

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, Philip. Before I get started, I'd like to take a moment on behalf of the ICD family and say thank you to the thousands of frontline workers during this COVID-19 pandemic that have taken care of our sick and elderly, helped the millions who have found themselves out of work, kept our grocery stores stocked, kept our highways open, provided the energy needed to keep our homes comfortable and our cars full of fuel, and to the men and women on the front line comforting those in our society, dealing directly with the most impactful effects of this virus. We at ICD are eternally grateful for your hard work and sacrifice during this extremely challenging time as we navigate the impact of this unprecedented event. As a country, we've overcome a lot in our history, and we'll also overcome this in no small part because of heroes like you.

Now turning to the business. Philip will go through the details of our results for the first quarter of 2020. In my prepared remarks, I want to talk briefly about our first quarter, offer some perspective regarding the current environment and how it's impacting the land drilling rig market and ICD and discuss some key initiatives we have undertaken in response to all of this. Obviously, the back end of the first quarter played out in ways no one predicted. The strong reaction by our customers to significantly lower oil prices was swift and dramatic. Unfortunately, I believe the recall that we are seeing still has a couple of months to play out. As recently as February, ICD had 22 rigs contracted, and we were in advanced discussions to start up 3 more rigs in our target markets by the end of March. As the COVID-19 virus firmly implanted itself in the United States in early to mid-March and we started seeing the global economy shut down as local, state and federal governments responded, we saw oil prices decline in unprecedented ways, culminating in the May WTI futures contract closing at a negative number on Monday, April 20, just before contract expiration. There was a first wave of upstream E&P CapEx cuts during March, followed by another wave of cuts during April as oil prices continue to fall and oil supply and storage concerns continue to mount, and it wouldn't surprise me if we see more cuts to expectations. These are some of the reasons why you saw analysts and others continue to revise lower, already reduced CapEx and rig count expectations for 2020 and beyond. As you saw in our press release earlier today, ICD's contracted rig count began to decline as the effects of the COVID-19 pandemic grew. We exited the quarter with 17 rigs operating, and since quarter's end, we've had another 6 rigs go idle as of the date of this call. This has happened against the backdrop of 367 rigs being laid down across our industry since the February 20 rig count of 774.

Last week's decline of 60 rigs means the rig count was at 407, representing a 47% decline over the last 2 months. The Permian alone dropped 34 rigs last week. Like everyone, I suppose, we expect to see this downward trend in working rigs continue throughout the second quarter. During the quarter, and prior to the onset of the COVID-19 pandemic, we successfully completed a handful of third pump upgrades to our fleet. In terms of contracting activity, prior to the COVID-19 taking effect, we executed 4 new contracts with 3 new operators and executed 4 extensions with existing customers during the first quarter. ICD had 1 contract early terminated at the end of the first quarter, and we've had 2 more early terminations here in the second quarter. Operationally, our ongoing safety and other operational initiatives continue to pay dividends, as evidenced by a year-to-date TRI are well below 1 and operational uptime approximately 99%. So as we transitioned into the COVID-19 downturn, our rig operations were performing exceptionally well.

Now I'd like to share some perspective about the actions ICD has taken to confront the significant challenges our industry faces today. In any environment, our first and most important concern is the safety and well-being of our employees, their families and those of our other stakeholders. I could not be more proud of how our team of professionals have responded and adapted to the current extremely challenging conditions. Our rig and field-based personnel have adapted well to the social distancing and other protocols prescribed in our infectious disease control plant, which was activated early March. Because of our coordinated planning and execution of our plan, we have avoided significant supply chain disruptions, ensuring we could continue to supply and operate our rigs in the new world of COVID-19.

Corporate, IT and other support functions have performed exceptionally well and supported the company without a hitch while working remotely for the past 45 days plus. Operationally speaking, COVID-19 has not had a material impact on us. And I thank the professional men and women that work at ICD for their diligence and perseverance and ensuring mission integrity during this unprecedented time.

In parallel with ensuring worker safety in light of COVID-19, we took actions beginning mid-March to rightsize our cost structure through reducing headcount, salary and other elements of compensation for all personnel. And arriving at our plan, we put everything on the table with a goal of reducing cost in order to preserve liquidity, meanwhile retaining our ability to provide daywork drilling services in the manner our customers expect. In terms of headcount and pay reductions, each level of the company, including the Board of Directors, executive management and every department within the company was impacted. Most of the support headcount reductions are transactional in nature and some were driven by the elimination of management layers, which is warranted given the lower levels of activity, which we envisioned.

Overall, we reduced the number of director and executive positions and reduced corporate and support headcount by approximately 40%. The net effect of these cost reductions is an expected drop in annualized cash SG&A of approximately $5 million compared to budgeted levels, and also a reduction in our operating cost per day on a steady state basis. Unfortunately, as our rig count drops, we will experience stacking costs associated with rig preservation, lease and storage as we deal with the unprecedented number of idle rigs we will need to address. Some of our operating costs are fixed in nature. So as our operating rig count moves toward trough levels, our reported cost per day metric will be under pressure driven by these necessary items and fewer operating days. We also suspended all capital expenditures except for essential maintenance items associated with operating rigs which reduces our capital expenditure budget by approximately $3 million or about 30%. Much of this CapEx budget was already committed during the first quarter on completed mud pump upgrades and equipment overhauls, thus go forward CapEx run rate for the remainder of the year and until operating conditions improve will be substantially lower. From a rig count trajectory perspective, based on what our customers have told us so far, we expect we will exit the second quarter with 6 rigs operating, including 2 working on natural gas directed projects.

Looking past the second quarter, we have 4 rigs with contracts expiring in the third quarter, 1 of which is drilling gas wells and 2 with contracts expiring late in the fourth quarter, 1 of which is working on gas projects. Recontracting opportunities today are few and far between. But there are a couple of conversations going on, and we believe our equipment, reputation and operating history in the Haynesville can bring us an opportunity or 2 if natural gas prices continue to improve, helped by the decline in the associated gas productions from the oil shale basins. From a day rate perspective, I would say there really isn't a spot day rate marker out there I could point you to or place any confidence in. Right now, for the most part, a working rig's technical specification or performance doesn't matter with respect to the oil directed projects. When your contract's up, the operator will return the rig to you, or may not wait and just early term the rig.

I'd like to spend a few minutes talking about liquidity at ICD. In times like these, keeping your eye on the ball is critical. And today, that ball is liquidity. Everything that we have done over the last 2 months has been to enhance liquidity for the company. We summarized our current liquidity in the press release we issued earlier today. At the end of March, we were sitting with almost $10 million in cash, a borrowing base of $20.1 million under our

ABL with availability of $8.6 million, and a committed $15 million term loan accordion that was undrawn. At the end of the first quarter, we did draw down some additional cash from our ABL, which increased our cash and debt balances at quarter end. Looking forward, our sources of liquidity will be cash on hand, availability under our ABL and availability under our term loan accordion.

In addition to declining cash flows from reduced activity, one of the challenges we have, which will evolve as this year plays out, will be driven by our AR balances, which will come down as a function of our reduced contracted rig count. We therefore expect availability under our ABL to decline as a result, which will reduce the eligible AR collateral balance that is used to determine availability. As we look out over the next couple of quarters, we expect we will need to draw down on our term loan accordion during 2020 to support operations and fund other nonoperating expenses. It was with this view, combined with the unprecedented deterioration in industry fundamentals, an uncertain macroeconomic backdrop, lack of capital market availability for micro-cap companies in the U.S. land oilfield service industry and after assessing the company's liquidity requirements and available sources of liquidity to fund operations, that the company applied for and received a $10 million loan issued pursuant to the Payroll Protection Program under the CARES Act, which will be used to fund permitted expenses under the referenced act. Philip will go through some of the details but this loan will be a very important source of funding for the company as we deal with the impacts of COVID-19 on our business. Obviously, when we talked about the new normal on previous earnings calls, we didn't expect what we've seen year-to-date.

However, I believe some of the important trends that we predicted will accelerate as a result of the current crisis, which includes the needs for further consolidation in the land drilling space, the challenges in finding growth capital in financial markets, our customers prioritizing efficiency and cost control over production growth and our customers maintaining a laser focus on maximizing drilling efficiencies. For the challenges within ICD's control, I believe we remain very well placed in this paradigm with a pad optimal fleet and technology offerings, which will enable our rigs to deploy some of the best drilling optimization solutions in the marketplace, and the results of these efforts will be meaningful to our customers. We have rationalized our SG&A structure and operating costs and are continuing to evaluate ways to reduce cost and, very importantly, have put in place scalable, robust financial and operating systems, including industry-leading HS&E and people development processes revered by our employees and our target customers.

Also, we work for a wide array of E&P companies, including many of the largest independents and super major oil companies operating in ICD's target markets. We have said many times, in the new normal for our industry, we believe further consolidation of pad-optimal rig fleets is an economic necessity for a whole host of reasons, and that could never be more true than in a COVID-19 world. We can't predict when further consolidation will happen, there are structural and social challenges that must be overcome. But ICD is a willing consolidation participant with a demonstrated capability. And we're extremely well positioned with institutional knowledge supported by robust systems and processes underlying a proven track record of successfully integrating competitors. We have shown our ability to unleash substantial value creation opportunities for our shareholders our employees and our customers through consolidation, and we're ready to execute on these initiatives again.

So summing all this up, I believe ICD is very well positioned to participate in the evolving need for consolidation. In the meantime, we have pulled and we'll continue to pursue the levers available to the company to help us weather the current storm. Management is properly incentivized and possesses and employs a pledger mentality. Our systems and processes, which support our operation are best-in-class. And our rig fleet is young, flexible and engineered to maximize manufacturing efficiencies for our customers. Our rigs are drilling optimization capable and ready for the continued focus and actions by our customers regarding ESG concerns and mandates once their focus returns to drilling oil and gas wells. We are firmly implanted with a strong brand and reputation for providing the safest and most efficient contract drilling services in North America's most prolific oil and gas-producing regions, which reside in Texas and the contiguous states.

So 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 $10.6 million or $2.82 per share, and adjusted EBITDA of $5.1 million. Excluded in calculating adjusted net loss and adjusted EBITDA was a noncash impairment of $16.6 million associated with the write-down of equipment and assets held for sale and $1.1 million of severance costs resulting from personnel reductions associated with COVID-19. With respect to other items during the quarter, reported revenue per day was $19,823, consistent with quarterly guidance and representing a sequential decline of $418 per day. Rig utilization of 66% came in slightly below guidance provided in our year-end quarter conference call, primarily due to rig count declines at quarter end caused by the COVID-19 pandemic. Cost per day of $14,648 was slightly higher than guidance, mainly due to reduced operating days and rig stacking costs that began towards the end of the quarter. SG&A of $3.8 million, including noncash compensation expense of approximately $0.6 million, came in lower than guidance with the difference principally relating to reduction in incentive compensation accruals. Depreciation, tax expense and interest expense came in consistent with our prior guidance.

During the first quarter, cash payments for capital expenditures net of disposals included $5.3 million associated with changes in accounts payable from year-end. Current year projects included completion of third pump upgrades and equipment overhauls completed or in progress prior to the COVID-19 pandemic manifesting itself.

Moving on to our balance sheet. At March 31, we reported net debt, excluding finance leases and net of deferred financing costs of $128.9 million. This net debt is comprised of our term loan and $11 million of revolver borrowings. Finance leases reflected on our balance sheet at quarter end were reduced by $1.2 million associated with payments and the return of certain lease vehicles as operating rig counts begin to fall at quarter end. In addition to borrowings at the end of the quarter to add cash to the balance sheet, anticipated borrowings under our revolver during the first quarter were associated with seasonal items such as ad valorem taxes and prior year incentive compensation payments.

At March 31, we had total liquidity of $33.4 million comprised of cash on hand, and $23.6 million of availability under revolver and term loan accordion. Our backlog at March 31 contracts with original terms of 6 months or more, stood at $26.4 million, all of which expire in 2020. And we had 3 rigs operating on short-term contracts at quarter end, not included in this reported backlog. As Anthony had mentioned, we expected to exit the second quarter with 6 rigs operating. We have 4 contracts with terms expiring throughout the third quarter, and 2 contracts with terms expiring late in the fourth quarter.

Now moving on to second quarter guidance on operations as well as liquidity. With the caveat that forward visibility is almost nonexistent with respect to customer intentions, we expect operating days to approximate 836 days, representing 9-point average rigs working during the quarter with an exit rate of 6 rigs operating. We expect revenue per day to come in between $19,800 and $20,200, and cost per day to come in around $13,600 and $14,000 per day. Excluding from these costs per day guidance items are early term revenues and stacking and furlough costs, which we expect to substantially offset each other during the quarter.

We expect SG&A expense to approximate $3.1 million during the quarter, including $600,000 in noncash stock-based comp. And after the second quarter, we expect an annualized run rate on cash SG&A to approximate between $9 million and $9.5 million annualized with stock-based compensation on top of that. We expect interest expense to approximate $3.6 million during the quarter, including $1 million of noncash interest expense and depreciation to remain relatively flat with the first quarter, and we expect tax expense during the quarter to be negligible. For capital expenditures, we have reduced our annual budget to $7.5 million, the majority of which was spent during the first quarter.

At March 31, we have $2.8 million of CapEx accrued in accounts payable that will flow through our cash flow statement and expect another $1 million or so in maintenance CapEx on top of that through the remainder of the year.

Now moving on to our balance sheet and financial liquidity. As I previously mentioned, at March 31, we had total liquidity of $33.4 million. Looking forward, we expect our required nonoperating expenditures will consist of $3.1 million per quarter of interest expense, approximately $1 million per quarter of finance lease payments and approximately $2.9 million payment that is shown as a current liability on our balance sheet as a payable to an affiliate. For the remainder of 2020, we would estimate these payments to be approximately $15.2 million in addition to CapEx. To fund these payments in operations, we expect to begin drawing down our term loan accordion as required. With respect to working capital and our revolver, although we will harvest cash as rig counts fall, as Anthony discussed, our revolver availability is tied to our eligible accounts receivable balance. Thus as operations fall, availability will fall. In other words, we don't expect our revolver to be a meaningful source of liquidity going forward to fund nonoperating expenses or cash flow shortfalls. Thus after assessing our situation, the unprecedented impacts of COVID-19 on our business and the lack of clarity of when the market will stabilize, we applied for and received a $10 million loan under the Paycheck Protection Program of the CARES Act. Funds from this loan can be used for payroll, utilities, leases, interest payments on certain obligations. The loan is eligible for forgiveness based on expenditures during the 8-week period following the loan, of which 75% must be payroll-related. The amount forgiven is based on a comparison of the company's pre-COVID headcount compared to the 8-week period following receiving the loan. Because the company had already begun reducing headcount beginning in March prior to receiving the loan, we do not expect the full amount of loan to be forgiven. Additional guidance is expected from the government on how loan forgiveness will be calculated, but we are operating right now under the assumption that approximately $3 million will be forgiven. Unforgiven amounts bear interest at 1% and are paid back in 18 equal monthly installments beginning November 27, 2020.

And with that, I'll 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 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 [2]

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Anthony, I wanted to start by asking a question about one of your comments on the Haynesville. I mean, clearly, you've been a big player there and for the past several years. And the natural gas outlook has at least improved somewhat over the past several weeks and months and so. Just curious what the nature of any potential discussions you're having with customers in the Haynesville are like today? I mean are those discussions even taking place today, or is it too soon? And do you expect some sort of uptick in rig count in the Haynesville towards the latter portion of 2020?

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

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Yes, Taylor, thanks for the question. Great question. It's good to talk about something positive. But yes, we have had and continue to have discussions with customers over there, both current customers, in other words, people that we are working for today or just recently worked for and then some additional ones that we've continued to stay in contact with over the last couple of years. As I think about the rest of the year, I mean that's the one area where there's some optimism, at least for the next couple of quarters. From my perspective, look, I'm encouraged by what you see happening in the commodity. You look at what expectations are in terms of associated gas. And what's going to happen there as wells get shut in, which is happening, as you know. I think there's reasons for some optimism, not just for the industry, but specifically for ICD here over the next couple of quarters. So yes, I am optimistic. There are discussions that are underway. I think that is some upside to some of the numbers that we think about over the rest of this year. Obviously, it's cautious optimism, just given what's happening big picture. But I love the position that we're in. As we've stacked rigs -- just so you know, we have strategically stacked some up in that area, again, on the assumption and expectation that it puts us at an advantage as we continue to talk to these customers as the rest of the year plays out.

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Taylor Zurcher, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research [4]

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Got it. That's at least encouraging. My follow-up is just on the current liquidity position. Right now, you've got $11 million drawn on the revolver. And it sounds like you'll tap into the $15 million accordion on the term loan at some point moving forward. And if we look at the debt covenants that you have in the revolver today, clearly, the availability on the revolver will come down with receivables. But do you expect -- will you need to put the $11 million you have drawn into the accordion? Or do you expect that $11 million to be relatively safe from a debt covenant perspective over the course of 2020?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [5]

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Taylor, this is Philip. There's 2 debt covenants that we've got. One is in our term loan, there's a minimum $10 million, minimum liquidity covenant and there's a springing fixed charge covenant that doesn't come into play in the revolver until we have less than $4 million of availability. So we're not there yet. We will be hard -- we will bring cash into the business as rigs stack and working capital. So that cash, some of that will pay down the revolver -- the revolver balance now. So we'll -- we just don't see the revolver as a meaningful source of sourcing. It will support the operations of the business, but it won't source our nonoperating expenditures just because the availability is going to come down. We will have to pay part of that revolver balance back as our rigs come back. But we will be getting cash in to do that as well as our working capital converts to cash.

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Operator [6]

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Our next question 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 [7]

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Maybe just following up on that line of questioning, specifically on the working capital front, Phil. What kind of cash contribution are you expecting on a full year basis from working capital?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [8]

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From -- as it goes down, yes, it's about -- I'd say each of our operating rig is probably $600,000 to $700,000 of positive working capital. So you're going to harvest that much cash, say, as we go moving from the 17 rigs or so at the end of the quarter that we had operating down to the 6 rigs that we expect. I don't have to -- I haven't done the math exactly in front of me. But it would be something like that, that we would -- that cash would come in the door.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [9]

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So $600,000 to $700,000 from rigs. So you go from 17 down to 6. So 11 times, whatever, $600,000 you perceive is the contribution…

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [10]

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Right. That's correct.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [11]

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Our working capital contribution. Okay. Great. You guys referenced you tapped into the CARES Act for the loan here, payment protection loan. So I'm assuming that shows up in your debt balance as you go into the second quarter. So should we look -- what we think the aggregate debt balance is going to be as we move forward, about $150 million, does that sound about right?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [12]

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Well, it would be what we have today, plus the $10 million we just borrowed under the CARES Act. And then you got the $11 million at March 31 that we would start paying that down with the cash that comes in on the working capital release, we'll use some of that to pay down. So that will probably get you close.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [13]

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Okay. And then, Anthony, in the context of exiting the quarter at 6 rigs. Again, coming back around to the prior question, maybe about natural gas basins or otherwise. What kind of discussions are you having with respect to putting some rigs to work above and beyond that 6 in the second half? I guess, look, I'm very well versed on the fact that every E&P company is pretty much shutting down during the course of the second quarter. There have been some conversations or some commentary from E&Ps about maybe increasing activity if WTI were to get back into $30 range. So just curious on your end, do you think you're going to flat line a fixed range for the rest of the year? And do you think there's a prospect you could put 1 or 2 rigs back to work through the third quarter and into the fourth quarter?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [14]

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No. I think it's -- it is the latter, Kurt. Look, everything you just laid out is consistent with what we're hearing. When I hear these inbound, one question that comes to my mind is, is it a drilling engineer that's trying to justify our position? Or are there truly business opportunities there? And the thresholds in terms of commodity that we hear customers talk about is kind of $2 gas and a $30 WTI. At above those levels, there's -- at least rigs aren't going to get released. There's some stuff on the margin that -- it feels like and sounds like our customers would increase activity. Just given the nature of the people we're talking about, like I said, it does include current customers. In some cases, it's incremental rigs. In other words, they're picking rigs up that they've dropped earlier this year or late last year. And in some cases, it would be new opportunities for the company, where we may have an opportunity to displace a competitor. We -- as you said, or as it was said earlier, ICD has a very strong reputation in the Haynesville. It's a reputation and a business that we've built ourselves. It didn't come through an acquisition or anything like that. And we get a lot of inbound calls and inquiries from customers as they think about activity over there. So you look at some of the rigs we've had running, they've performed exceptionally well. They're very safe. They're very efficient. Crews have been together a long time. So as customers think about go forward operations, obviously, we're in the mix. And I think in some ways and in some cases, certainly, I think we're at an advantage. We just need to see the opportunity evolve into a contracting opportunity. And I am optimistic that we will have the wins in that area. Obviously, like you said right now, second quarter, there's not a lot that's going to happen. But the opportunities that we're talking about are kind of July, August and beyond, and we'll see how the summer plays out. But I think I would say that things are lining up that I would expect us to put a couple of rigs back to work up there later this year.

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Kurt Kevin Hallead, RBC Capital Markets, Research Division - Co-Head of Global Energy Research & Analyst [15]

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Great. And then just one last follow-up. Do you expect to be EBITDA positive during the second -- during the remainder of the year?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [16]

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It's going to depend on how many rigs are running, Kurt, and we just don't know the answer to that. If it's less than 6, that's going to be a challenge. If it's more than 6, then we've got a chance to do that. But it's going to -- there's a lot of variables in that.

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Operator [17]

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The 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 [18]

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Just a follow-up on your customer conversations. For customers that might want to continue drilling, are you guys having more discussions around different pricing models instead of maybe just seeing outright day rate cuts?

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

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Yes. I think most people are looking at this straight up day work model, Brian, when we talk to them. Like everybody, we've been interested. We've even had a couple of performance based contracts. We like it. Obviously, there's got to be some upside in the arrangement for us. But right now, I would suggest that most customers are looking at every way as possible to lower their cost. And I think more of them are focused on the day rate -- day work type model today.

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Ryan James Pfingst, B. Riley FBR, Inc., Research Division - Associate [20]

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Got you. And in your prepared remarks, you mentioned consolidation, what are some of the paths you guys could potentially take on the M&A front in this kind of environment?

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [21]

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Well, I mean, not any cash buyers out there, right? So you have to be focused on the big picture. The big picture, in my mind, is more capital efficiency that would result from the consolidation. You think about it, there's half a dozen companies or maybe there's more that all kind of -- dozen, 2 dozen type rigs in their fleet. We're all spending $10 million to $15 million a year in SG&A. We're all pursuing the same customers. We're all working with the same vendors. And look, ICD has demonstrated now a very good ability of being able to do this and wring out every bit of synergy opportunity that's there. And as we think about the reasons, it's probably on a relative value basis that you get something like that done. It has to be. Debt, when you look at opportunities, the debt load on the company has -- obviously gets factored into that. There are social issues that have to be resolved as well. But my point in bringing it up on the call is that, look, we've been banging this drum for a while. We think it's necessary. We think what's happening now in the industry is going to force some hands. And we're optimistic about our chances of trying to get some consolidation done.

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Ryan James Pfingst, B. Riley FBR, Inc., Research Division - Associate [22]

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Got you. Maybe just one more, if I could. Can you guys give a little more detail on how cost structure initiatives are going to affect the daily operating expenses through the rest of the year? Maybe if you guys get more rigs to work, are we going to see the costs come down and stay fixed (inaudible).

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [23]

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Yes. So yes, operating -- how many operating rigs does matter as far as fixed cost absorption goes. For our guidance for the second quarter, we were at 13.6 to 14. I would expect that to come down a little bit even at say, 6 rigs. And if that's what it was in the third quarter, we're running, obviously, if we're running more than that, then it's a little better, if we're running less then it's a little worse. But yes, if we can get -- the more rigs we get back to work, then clearly, there's fixed cost absorption that helps us out. One of the things we are dealing -- going to have to deal with, actually, they're stacking costs this quarter that are substantial as a rig comes in the stack. But then there's the ongoing lease payments we make where we stack the rig and there's some maintenance you'll do on the rig to keep the engines running and things like that as you go forward. That's going to impact our cost per day as well and create some inefficiencies in this environment.

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Operator [24]

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The 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 [25]

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Really just a couple of small ones left on the liquidity front. You referenced 3 early terms. It didn't sound like those were included in the contracted count or the exit of 6 count, and there's probably not much duration associated with those contracts. But how do you -- how are we accounting for the cash flow associated with the early terms in the Q2 guide? And is it worth mentioning those dollars?

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [26]

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So when we gave the revenue per day and the operating rig count and the cost per day, we excluded anything out about those early terms. The revenue, we're going to get on the early terms between $1.5 million and $2 million, that's probably going to be offset by the stacking costs that we have that are coming in. We're going to have a large number of rigs come in that you've got to put, do preservation on and things during the quarter, and that's going to be a chunk of change. And there's some furlough opportunities that we're able to take for our employees during the quarter as a result of getting the CARES Act loan that those costs will probably offset the early term revenues during the quarter.

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Daniel Joseph Burke, Johnson Rice & Company, L.L.C., Research Division - Senior Analyst [27]

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Okay. And Phil, I might have missed this, is stack cost in your op cost per day?

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

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No, it's not. No, it's not, that preservation.

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Daniel Joseph Burke, Johnson Rice & Company, L.L.C., Research Division - Senior Analyst [29]

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Okay. And then maybe one other one. Just again -- you have the PPP funds and diligent in how you use them. But when we think about the use of the accordion as well as you highlighted, is that -- should we think of that as really just offloading current borrowings on the revolver? Or will the accordion also be needed to fund in addition to that ongoing cost of the business? I guess I'm just trying to figure out how much -- in a way, it's a question about free cash flow.

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Philip A. Choyce, Independence Contract Drilling, Inc. - Executive VP, CFO, Treasurer & Secretary [30]

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Yes. I think the accordion is going to be important and the money can be fungible here. But if you're booking it in the buckets, the accordion is going to be really important for our nonoperating expenditures as we look forward. And we'll look to draw it down as slow as possible because it's expensive cash. But it will be important as far as funding nonoperating expenditures is kind of how I think about it.

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Operator [31]

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This concludes our question-and-answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks. Please go ahead.

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John Anthony Gallegos, Independence Contract Drilling, Inc. - Director, President & CEO [32]

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Okay. Chuck, thank you. Everyone, we appreciate you dialing in, taking time this morning to participate in the call. We'd ask that everybody be safe, take care of one another. We do look forward to talking to you and hopefully, eventually seeing you again one day soon. So we'll end the call from here. Thank you.

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Operator [33]

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