Good morning. Welcome to the Independence Contract Drilling Third Quarter 2020 Financial Results and 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. Go ahead.

Good morning, everyone. And thank you for joining us today to discuss ICD's third 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'll 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. J. Gallegos: Thanks, Philip. And Philip will go through the details of our financial results for the third quarter of 2020. In my prepared remarks, I want to talk about the evolving market dynamics and the challenges and opportunities for ICD in our industry and offer some perspective about the current rig market. Without a doubt, during the third quarter, ICD and our industry experienced the full effects of the downturn resulting from the unprecedented destruction in demand of oil and gas caused by COVID-19. Indeed, the Baker Hughes U.S. land rig count fell to a low of 244 rigs during the quarter, representing a 40% decline from previous all-time lows experienced in 2016. This drove us to reporting an EBITDA loss for the quarter as our rig count troughed temporarily to an all-time low of 3 operating rigs early in the quarter, and several higher-priced legacy contracts expired during the quarter, even with better-than-expected results from our cost rationalization and control efforts. However, as we signaled on our last quarterly conference call, we expected the third quarter would represent the trough for U.S. land drilling activity and ICD's operating rig count. And as we sit here today, that appears to have been an accurate forecast. Since sharing that perspective, we entered the third quarter with 5 rigs drilling, temporarily dropped to 3, which I mentioned, and exited the third quarter with 6 rigs drilling. Since the end of the third quarter, I'm pleased to announce we have reactivated 2 additional rigs and continue to be in active discussions regarding multiple other opportunities for reactivations later in the fourth quarter as well as during the first half of 2021. There are several factors driving our recent incremental rig adds and our expectations for additional reactivations. You've heard me discuss on prior conference calls ICD's leading presence in the Haynesville and East Texas gas plays, a market ICD organically developed throughout the 2015 and '16 downturn. Drilling in these high-pressure, high-temperature environments acquired expertise and an established reputation, which ICD has. It's not as simple as moving a rig in from an oil play to a gas play, customers expect your crews and operations to be experienced operating in these challenging environments. ICD has the expertise and established reputation in these markets. And as natural gas pricing has stabilized and improved, in large part due to declines in associated gas production from declining oil production, we are seeing demand for our rigs outpace the overall market. Of course, we are also seeing additional opportunities based upon our oil driven customers' confidence with oil prices recently stabilizing at above $40 or below. Obviously, there's been a little pullback from there in the last week, but that has not yet muted any conversations we are having. We would expect further reactivation opportunities to develop in oil-based plays above what we are currently seeing once customer confidence in $50 a barrel WTI develops. For the most part, recent and near-term opportunities are skewed toward private operators. And it does appear that more operators are open to considering performance-based contracts. We'd like to see this trend continue as everybody can win in that type of contracting structure. In addition to significantly improving our operating rig count during the quarter, we continue to improve our overall financial liquidity by successfully completing our ATM stock offering, raising additional gross proceeds during the quarter of $3.6 million. At quarter end, we had $18.8 million of cash and our overall liquidity was $39 million, consisting of $5.2 million of availability under our undrawn revolver and $15 million under our term loan accordion, along with cash on hand. As we mentioned on previous calls, our revolver would not be a significant source of liquidity when our rig count reach trough levels. However, as we move forward into what we expect to be an improving operating rig count for ICD, our revolver borrowing base will grow as accounts receivable increase. Thus, we expect our revolver to again be a source of liquidity available to us to fund required working capital investments for rig reactivations in an improving operating rig count environment. Obviously, improving market dynamics is a welcome sight, but it does not come without its challenges as ICD and our industry pivot to expanding market dynamics. On past conference calls, you've heard me discuss what I believe are ICD's industry-leading operating and people development processes and procedures. And in this environment, I believe they are providing a real competitive advantage. Over the past 60 days, we have successfully recruited and reactivated 5 rigs on budget and met our customers' compressed timetables and incurred minimal operating downtime post start-up. As we move forward, I expect our established systems and processes, which support our culture for safety and operating excellence to increase in importance as we are considered for additional contracts. Although we have retained experienced personnel to fill all of our skilled and support positions as we reactivate rigs, ICD and others in our industry will at some point need to train new, entry-level floorhand personnel as our industry continues to recover and reactivate rigs. At ICD, we have demonstrated systems and processes in place to manage these challenges effectively. In addition, as rigs that were stacked for longer periods of time are reactivated, there will be all of the expected costs and challenges associated with getting these rigs ready to resume operations. For ICD, we have followed detailed stack-out preservation and stacked rig maintenance procedures for all of those rigs in order to minimize reactivation costs, CapEx and NPT, and we are seeing the benefits from these investments already. Of course, as we pivot to an improving operating environment, I do expect rig-on-rig competition to remain high. The simple reality is that the U.S. land contract drilling industry is bouncing off an operating base that was at an all-time low. In that environment, increased competition is unavoidable. Everyone is fighting hard for each contracting opportunity. At this beginning stage of the recovery, where we are today, historical operational excellence and customer confidence in a drilling contractor's ability to successfully and timely reactivate a rig and operate safely with minimal operational downtime is very important. ICD is very well positioned in this arena with demonstrated capabilities across our target markets. In addition, because of the extremely low operating base and the large number of stacked, super-spec rigs, there are going to be less opportunities for equipment differentiation between the high-specification rigs that are being reactivated today. You've heard me talk on past conference calls that the market decline that really began in late 2018 made it very difficult for ICD to realize the true benefits from its merger with Sidewinder. Well, I think in the post-pandemic recovery, we will begin to see those benefits manifest themselves. ICD now markets rigs with 3 pumps, 4 engines and rigs with greater than 27,000 feet of racking capacity. And we continue to make progress in the field with respect to drilling optimization software. And our rigs continue to exceed our customers' expectations, including recent record wells in the Permian and Haynesville, measured by days to TD. In one case, according to one of our Haynesville customers, we helped them save over $1 million on a well during October. The overall point being, even as competition increases in this recovery, we expect to win more than our fair share of these battles, including with customers for whom we've never had the opportunity to work for until now. And of course, in the business climate I just described, there's going to be day rate pressure. And because the industry did not enter this downturn with as much contract backlog compared to previous downturns, there's going to be less backlog support to help insulate operating margins. Today, day rates on rig reactivations are typically in the mid-teen range with opportunities for higher day rates based upon rig configuration and other contract terms. For the most part, recent reactivations have been for short-term pad-to-pad type tenors, and thus are not included in our reported backlog numbers. As we enter next year, I expect to see day rate improvement as markets continue to heal, in particular, as the initial low-hanging fruit type reactivations dry up and reactivation costs increase for rigs that have been stacked longer, I believe day rate improvement becomes an economic necessity in order for contractors to justify taking a rig out of stack. In addition, and very important for ICD's recently reactivated and recontracted rigs, first quarter 2021 contract extensions and new contracts on hot rigs should see day rate improvement compared to fourth quarter spot day rates. Given the increasing importance of ESG matters, I would be remiss if I did not mention that ICD continues to emphasize and when possible, utilize the carbon reducing features of its drilling rigs. ICD has been touting the dual fuel capabilities of its drilling rigs since our inception. Currently, 3 quarters of our operating rigs are utilizing -- are in the process of utilizing the dual fuel capabilities of our rigs, and we expect this percentage to only increase in the future. Also, we have operated ICD rigs using the electrical power grid, and we continue our ongoing process of reducing cycle times, loads and other environmental impacts associated with moving our rigs from pad to pad. Those of you that follow the company know that we've been very forward-leaning on the governance front, including tying a substantial portion of executive comp to quantifiable measures, which are closely aligned with our shareholders' interest. On the social front, we'll once again undertake an aggressive campaign over the holidays to give back to the communities where we operate through our [ Santos ] roughneck campaign and other initiatives including charitable efforts here in Houston, where our corporate headquarters is based. On the capital side of things, all additional rig conversions and major upgrades remain suspended, and CapEx remains focused solely on maintenance items as well as third pump, fourth engine configurations. In this regard, we already own the pumps and engines to outfit any of our rigs we would expect could be mobilized over the next 12 to 18 months with this configuration. So summing all of this up, I believe ICD is very well positioned to execute operationally as we recover from this unprecedented downturn, and we are on a pathway to drive returns for all of our stakeholders. Our financial flexibility has improved during this downturn, and our management team remains pledgers, meaning we are incentivized accordingly to focus on cash flow generation and financial returns over the longer term. Our systems and processes, which support our operations 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 of our customers regarding ESG concerns. 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 in a contiguous state. With that, I'll turn the call back over to Phil so that he can walk us through the financial results of the company.

Thanks, Anthony. During the quarter, we reported an adjusted net loss of $15.5 million or $2.73 per share and an adjusted EBITDA loss of $0.5 million. With respect to other items during the quarter, rig utilization of 17%, representing approximately 5 average rigs, came in higher than guidance provided on our prior quarter conference call due to the reactivation of additional rigs during the back half of the quarter. As Anthony mentioned, we also have reactivated additional rigs since the end of the quarter and absent any additional rig reactivations, expect utilization to increase by almost 50% during the fourth quarter compared to third quarter averages. Revenue per day of $18,078 came in lower than guidance based upon contract and fleet mix associated with additional rig reactivations at prevailing spot rates. Revenue per day stacked exclude approximately $1.2 million of early termination revenue recognized during the quarter. They also exclude pass-through costs of approximately $800,000 during the quarter. On a sequential basis, we had 2 higher day rate contracts expire during the third quarter, which contributed to the sequential decline. Looking forward, we have 2 rigs operating under higher legacy day rate contracts. Both of those contracts are scheduled to continue through the end of the year. Cost per day of $14,155 was also favorable compared to guidance and reflect economies associated with higher operating days compared to expectations as well as strong cost control. Cost per day exclude approximately $900,000 associated with rig reactivation and deactivation costs during the quarter. Cost per day also exclude unabsorbed yard overhead costs of approximately $500,000 and pass-through costs of approximately $800,000. SG&A expenses of $2.8 million included noncash compensation expense of approximately $700,000. This was sequentially lower and lower than guidance. Sequential improvements in cash SG&A costs reflect cost-cutting initiatives implemented during the quarter, which exceeded our original forecast as well as reduced furlough costs. Depreciation expense came in slightly lower than forecast and tax expense and interest expense came in consistent with our prior guidance. During the quarter, cash payments for capital expenditures were approximately $600,000 offset by proceeds from asset disposals of $1.4 million. There's approximately $600,000 of CapEx accrued at quarter end that we expect will flow through the cash flow statement during the fourth quarter. Moving on to our balance sheet. At September 30, we reported net debt, excluding finance leases and net of deferred financing costs, of $118.3 million. This net debt is comprised of our term loan and $10 million PPP loan. Finance leases reflected on our balance sheet at quarter end were approximately $9.5 million. I want to point out that our entire PPP loan balance was reclassified to long term based upon new guidance published by the SBA. We currently expect approximately half of this balance to be forgiven and the payments on the unforgiven portion to begin during the fourth quarter of 2021 and continue through April of 2022. At September 30, we had total liquidity of $39 million, comprised of $18.8 million of cash, $15 million available under our term loan accordion and $5.2 million available under our revolver. Our backlog at September 30 stood at $12.7 million, 56% of which expires in 2020. And I want to point out that our backlog excludes contracts with the original terms of less than 6 months. Now moving on to fourth quarter guidance. Based upon contracts we have in place today, we expect the operating days to approximate 665 days, representing 7.2 average rigs working during the quarter. Additional reactivations that occur later in the quarter could modestly improve this, but for the most part, would benefit 2021 operations. We expect revenue per day to come in between 16,800 and $17,000 per day and cost per day to come in around $13,600 and $13,800 per day. On the revenue side, this guidance includes 2 rigs earning day rates under legacy contracts as well as our 1,000 horsepower rig that earns lower day rates than the rest of our 1,500 horsepower ShaleDriller fleet. These per day amounts exclude pass-through revenues and expenses. We do not expect to earn any early term revenue during the quarter. Excluded from cost per day guidance is approximately $800,000 we expect to incur during the fourth quarter on 2 known reactivations and potential reactivations at the end of the quarter and beginning of next year. We also expect to incur an additional $640,000 on stacked rig and unabsorbed overhead costs during the quarter. Also pass-through costs are excluded from this cost per day guidance. Sequential decreases in revenue per day reflect a higher proportion of operating rigs earning day rates at prevailing spot rates. And again, as mentioned, we have 2 remaining higher day rate contracts benefiting the quarter, both of which expire at the end of the year. We expect SG&A expense to approximate $2.8 million during the quarter, including $500,000 in noncash stock-based comp. We expect interest expense and depreciation expense to be flat with the third quarter and tax expense to be approximately $100,000. For capital expenditures, we expect approximately $1.1 million to flow through our cash flow statement for the remainder of 2020. Now moving on to guidance regarding our balance sheet and financial liquidity. As I previously mentioned, at September 30, we had total liquidity of $39 million. We previously discussed on our conference calls, various actions we took with our term loan lenders to enhance liquidity. And in addition, as I mentioned, recent PPP loan guidance and rules have pushed back repayment time lines on that loan, increased our expected forgiveness amount. Looking forward over the next 12 months, our required nonoperating expenditures will consist of interest expense and finance lease payments, aggregating approximately $12.2 million. CapEx and operating uses of cash will be in addition to this, and any asset sales will be a source of cash. With respect to working capital on our revolver, as rigs reactivate, working capital investments will be required and will be a use of cash. However, we expect to see corresponding increases in our revolvers accounts receivable-based borrowing base. That will provide additional liquidity to finance these investments if necessary. And one final item, we expect weighted average shares to approximate 6.1 million during the fourth quarter. And with that, I'll turn the call back over to Anthony. J. Gallegos: Thanks, Philip. I have no further comments at this time. Operator, let's go ahead and open the line for questions.

[Operator Instructions] Our first question is from Kurt Hallead from RBC.

So I think where I'd like to start is, give me a sense, Anthony, from your perspective, as you look at the prospect of activating a couple of more rigs here before the end of the year. How many do you think you could potentially -- what's the underlying demand pull-through for additional activations as you get into the first quarter? And then at what point do you think you could start to see some better pricing for the rigs that are going to be coming back into the market? J. Gallegos: Well, Kurt, thank you for those questions. Look, obviously, we're very excited about what's played out for us here over the third quarter. Happy to say, as you read in the press release, that, that momentum for ICD has continued as we've entered into the fourth quarter. Starting to hear some feedback and have some discussions with certain customers about how they're thinking about 2021. Obviously, all kind of bounces between 41, then it's down to 38. So it's up today. Depending on when we have those conversations with people, they may have a different view about how they think about next year. But looking at the opportunity set that's in front of ICD, we're pretty optimistic that we'll continue to see this momentum in our contracted rig count. Very excited about what I see playing out in the Haynesville, which, as you know, is a core market for ICD. Just to kind of put that into perspective, there's 36, 37 rigs running in that basin today. We're just over 10% of market share. You don't have to go back very far, say, 2018 time period when that rig count -- contracted rig count was double that. And certainly, with what we're seeing in gas prices today and discussions that we have underway with customers, pretty optimistic that, that rig count is going to continue to tick up over the next several quarters. If you go back, it was a long time ago, but 2008, that rig count was in the triple digits. So not saying that's necessarily where it's going to go, but I think there's an awful lot of runway there for ICD and very optimistic that we'll continue to earn more than our fair share as measured by market share of those opportunities. With regard to your second question on pricing, it's -- as I noted in my prepared remarks, it's still very, very competitive out there. We're coming off an extremely low base. There's a lot of high-spec equipment that's laying around. You have some contractors. For the most part, I think large industry players are being disciplined, but you still have some people around the French that are bidding very, very aggressive. And I think until they get those rigs out or it's obvious they can't put them back to work, I think that's going to continue to be a drag on the market. So look, we think the rig count is going to continue to tick up. We think it will continue to increase quarter-over-quarter throughout next year. We're probably a quarter or 2 away before we can begin to see real pricing improvement. But in the meantime, for ICD, it's making sure that we can secure the opportunities that are in front of us, to keep our rigs contracted, obviously working safe, keeping our customers happy and ensuring that we do everything we can to shore up and maximize liquidity so that we have a runway to what we believe will be a very improving market over the next several quarters.

Great. And then, Phil, on your end, right? So the guidance that you provided for fourth quarter, it looks like that could map you out to about a breakeven EBITDA level. Do you agree? And then secondarily, as you look out into 2021, with some of these rig activations happening in the first part of the year, do you think you'll be able to generate positive free cash flow?

So I think I'm probably guiding still to an EBITDA loss in the fourth quarter, Kurt, would be kind of how I looked at it. When you think about free cash flow, we need to get some more rigs out to cover the [indiscernible] to cover the CapEx and those types of things. So depending on where day rates are, kind of giving you kind of some general [indiscernible] here, if we're running an $18,000 a day, revenue per day in a quarter, and I've got 13 -- 12 to 13 rigs running, I think I should get close to cash flow breakeven there. Obviously, we're not -- the revenue per day guidance we gave today is lower than that. So we'll need some day rate improvement. And we'll need to get some more rigs out to get there. That feels more like a -- if you look at the cadence of what's going on, that's probably -- could it be the second quarter? We don't know. It's probably more likely a back half of the year type of thing where we return to that. If you look at the cadence of what's going on would be kind of the best way I could think about that.

Our next question is from Ryan Pfingst from B. Riley Securities.

Just a couple on the 2 additional reactivations after the end of the quarter. Could you speak to the customer type on those? And maybe if the initial contracts cover the cost of those reactivations? J. Gallegos: Yes. Great question, Ryan. With respect to the customer, they're private, which I think is an important point that I should illuminate. If you look out over the last 4 weeks, the majority of the rigs that have gone back to work have been for privates. I think that's important as you think about ICD. We've set the company up, and you can look in our history and see we've worked for the biggest of oil companies, but we work for a lot of privates, too. Great relationships with those customers. And the fact that they are the ones that have been picking up rigs over the last several weeks has been very, very beneficial for ICD. So pretty excited there. I expect that's going to continue. I do think as we roll into 2021, you are going to see some of the larger independents begin to pick some rigs back up. Some of those will be rigs that have been laid down that were on contract, that were on standby. But I think there'll be a few incremental adds to that as well.

To answer the question on the breakeven, they are going to pay for the reactivation costs. Most of the reactivation costs you're seeing are we have to bring the crews back, and there's a few things you have to do with these initial rigs. There's not a lot of money. It's probably a couple of hundred thousand dollars. The -- one of the things you see is that we're not adding our support group. We've got a lot of kind of just minimum amount of support we need. And as we get rigs out, those costs -- you're seeing our cost per day go down. And you'll continue to see those go down as we get better absorption of those costs because the real only incremental cost on a rig reactivation is going to be variable. It's going to be at the rig level, it's the crew and the operating of the rig. And those are -- we're getting real margin there for those rigs. J. Gallegos: Yes. Ryan, I would just add, I mean we've turned down a couple of opportunities where the start-up costs could not be recovered on a cash-on-cash basis in the primary term of the contract. So trying to be very disciplined and as careful as we can be on those issues. Obviously, you want positive cash flow, and that's the goal. If we didn't think there was a good follow-on opportunity either with that customer or another customer in that basin, you might not undertake some of the reactivations. But yes, at a minimum, we want to recover the cash that we're investing on the front end before we start up a rig.

Got it. I appreciate that additional detail there. And then turning to the leading edge day rate, Anthony, you've already given some really good detail. But could you maybe give us an idea of where today's range is and -- or even how that compares to 3 months ago? J. Gallegos: Yes. I think at best it has moved sideways. It's not uncommon when you come out of a downturn for -- when you begin to see the market improve, to actually see a day rate degradation. I think we've seen that here over the third quarter. Like I said earlier, it's very, very competitive. It really is dependent upon what you're bidding. For the most part, 4 gens, 3 pumps is what's going back to work today. But if you're talking to a customer that is -- that wants the technology or requires additional racking capacity or something like that, obviously, the day rates for those opportunities are higher than the range that we've put out this morning. But mid-teens is kind of where the standard run of the mill, 3x4 or 4x3 type situation is today. And then you just add to that based on the individual requirements of that particular customer.

And then just one more on labor. As activities picked back up and potentially pick back up meaningfully here in the near term, have you guys seen any issues with crewing? Or do you see potential concerns with crewing going forward? J. Gallegos: So far, we have not. Look, we were able to furlough a lot of people over this downturn. Certainly the PPP loan that we secured, that was the purpose of it, and we took advantage of that opportunity and did that. So we've called all of those people back here over the last 6 weeks or so. We've been reaching back into our former employee base, people that were let go earlier and calling them back as well. So far, we've been able -- as we've started up the rigs that we've started up, we've been able to do that with former ICD employees. You're bringing up a great point. I think this is going to be a challenge for the entire industry as we roll into 2021, not just on the drilling side, but the completion side as well. Where most companies have cut back pay to some degree, depending on what sector of the economy you're looking at, there's opportunities out there for people outside of the industry. This is the second pretty nasty downturn we've been through in a very short period of time. So I think people are going to wisely ask themselves the question, is this an industry that we want to be in. I think the issue around people is going to become a major bottleneck for the industry as 2021 and especially beyond plays out. So we haven't had a job fair recently. We had some job fairs earlier this year. We are dipping back into those names and starting to contact people. We're actually scheduling our first orientation. It will happen here in the next couple of weeks for people that we're hiring from outside the company. We feel pretty confident that through names that we have from prior efforts and certainly referrals from people within ICD today that given the cadence that we see rigs going back to work over 2021 that we're going to be able to manage this. Our systems and processes are there that are going to help ensure operational integrity, things like that. So we feel like we've got a pretty good handle on this issue. But I think you're wise to raise this because, like I said, in my mind, this is going to become a major issue for the industry.

This concludes our question-and-answer session. I would now like to turn the conference back over to Anthony Gallegos for closing remarks. J. Gallegos: Okay. Well, thank you. Look, everybody, I want to say -- we want to say thank you to everybody for making time to dial in today and listen and participate. We will not talk to you again for a couple of months. So I want to wish you all good health and safety, a nice holiday season, including a Happy Thanksgiving and a very merry Christmas. Everybody be safe. And with that, we'll end the call.

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