Good day, and welcome to the Independence Contract Drilling, Incorporated, Second Quarter 2021 Financial Results and Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Mr. Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead, sir.

Good morning, everyone, and thank you for joining us today to discuss ICD's second quarter 2021 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 on our non-GAAP measures. With that, I'll turn it over to Anthony for opening remarks.

Hello, everyone. Philip will go through the details of our financial results for the second quarter of 2021 in a couple of minutes. In my prepared remarks today, I want to focus on 3 things: a brief summary of our financial performance during the recent quarter, current market trends that we're seeing and some commentary about our outlook. For the quarter, we’ve reported an adjusted EBITDA loss of $369,000 from an average working rig count of 11.8 rigs. This represented a sequential quarterly improvement in adjusted EBITDA of $1.6 million generated from only a modest sequential increase of 1.5 average operating rigs. Margin per day increased sequentially by approximately 13%. Steady dayrate improvement drove much of this increase, but our results continue to benefit from our cost rationalization and cost control efforts implemented last year and better absorption of fixed and support cost as a result of more rig activity. We also spent less on rig reactivations than anticipated. Philip will go through more of the details, but given our continued success in reactivating rigs and getting steady dayrate increases on contract renewals, we expect to return to positive adjusted EBITDA during the third quarter and remain on track to reach our goal of exiting 2021, generating positive free cash flow. Overall, liquidity at quarter's end stood at $35.4 million, an improvement from March 31. During the quarter, we selectively accessed our equity line of credit and ATM programs, raising approximately $2.6 million in gross proceeds at an average price of $3.60 per share. As mentioned on our prior call, we also took advantage of the PIK interest feature under our term loan with respect to our interest payment due at the beginning of the second quarter. Overall liquidity consisted of $6 million of cash on hand, $11.3 million of availability under our undrawn revolver, $15 million under our term loan accordion and $3.1 million remaining available under our equity line of credit. Now on to the business. Our rig contracting goal for the first half of 2021 was 15 rigs by the end of the second quarter. We achieved that with our 14th and 15th rig contracted and spudding their first wells in July. 8 are in the Permian, 4 in the Haynesville and 2 in South Texas and 1 in the Austin Chalk. Using August 2020 as the baseline, this is more than a fourfold increase in ICD contracted rigs compared to an approximate 2x industry-wide increase over the same period. Overall, since the beginning of the second quarter, and including the 2 rigs reactivated in July, we have reactivated 4 rigs, including 3 300 Series rigs and stacked our loan 100 Series rig, which was replaced by a 300 Series rig. I think this is a good time to highlight why we believe our 300 Series rigs represent an underappreciated value proposition inherent in ICD. We acquired these rigs in the Sidewinder merger. But until recently, we've never had the opportunity to market these rigs to ICD customers in an improving rig count environment. For example, we had 3 of these rigs operating in February of 2020 pre-pandemic and already have 6 operating today with more reactivations planned as the market continues to improve. Our marketing team has done a fantastic job marketing the value proposition of these rigs to our customer base, and these rigs are a big reason why ICD utilization growth is substantially outperforming the overall market. Looking forward at future reactivations, we expect those to be predominantly 300 Series spec rigs with our goal to have approximately half of the operating fleet comprised of this spec of rig. In comparison, we only had 14% of these types of rigs in our operating fleet right before the pandemic. So in addition to strong utilization, we expect these rigs to drive forward dayrate and margin momentum even in comparison to prior historical levels. For the industry in ICD, the second quarter was a continuation of the acceleration trends we saw during the first quarter, albeit at a slower pace as we expected. For the remainder of the year, we expect to continue to see rig count improvements. However, even with the improvements in commodity prices, we expect these improvements to be at a more modest pace compared to the first half of the year due to the fiscal budget calendar, lack of capital access and continued financial discipline on the part of our customers, E&P companies. Towards the end of this year and into next year, we do expect to see a step-up in demand in rig count. Even with continued financial discipline by our customers, we expect their 2022 CapEx budgets to increase based upon higher commodity prices and legacy hedges rolling off. We also expect a greater proportion of their budgets compared to 2021 will be directed toward drilling new wells, simply based on the tremendous decrease in DUC inventories we've seen throughout the year. We are seeing all of this play out in our conversations with our customers and in our contract discussions. While dayrates across our industry today are lower than what they need to be to satisfy expected demand for more rigs, we continue to see steady dayrate improvement on contract renewals and given our current short-term contract structure, expect to continue to realize improvements on renewals throughout the remainder of the year. We believe an important barometer on dayrates is when our customers begin approaching us regarding term contracts with longer tenors, such as one year. And recently, these opportunities and discussions have started to appear. I believe this is a function not only of the factors I just mentioned, but also a recognition on the part of our customers of supply tightness, which is evolving in the rig market and more confidence on the part of our customers and the overall outlook for commodity prices going forward. Overall, price competition has been more intense in the Permian Basin compared to the Haynesville, even though there are substantially more rigs working in the Permian. I believe this is a function of a larger number of competitors and diversity of work prospects and rig requirements in the Permian. In the Haynesville, where ICD is a key player and operations are targeting high-pressure, high-temperature natural gas plays, operating requirements are more challenging and drilling contractors need the equipment and required institutional expertise to drill these technically demanding wells. Thus, there are fewer competitors and less price competition. Operating requirements in the Haynesville also are more tilted toward rigs with higher racking and setback, such as our 300 Series rigs, which are in very short supply across all markets. However, as supply tightens, the Permian is starting to catch up in our highest dayrate contracts since the onset of the pandemic was recently executed for work in that basin. Our contracts are predominantly pad to pad contracts. And on renewals, we continued to secure dayrate increases in the $500 to $1,000 per day range and bigger increases for our 300 Series rigs when we're able to match customer requirements with those rigs capabilities. Current spot market dayrates for our 200 Series rigs have been in the $16,000 to $17,000 range plus adders, while current spot market dayrates for our 300 Series rigs, which are in shorter supply, are currently higher in the upper teens. Dayrate bias is higher for both classes of rigs. Compared to the last three months, we are seeing a significant uptick in demand beginning in the September, October time period. And as mentioned, we are now being presented with some term contract opportunities beginning in the same period. Much of this incremental demand is for work lines that extend through much of next year as customers begin preparing for 2022 activity and, of course, higher commodity prices and legacy hedges rolling off. So there are a lot of factors that we believe will lead to continuing dayrate improvements, but most important is the limited supply of super-spec rigs. As discussed on our last conference call, utilization for true super-spec rigs is much higher today than we believe most people realize. Most importantly, there are minimal super-spec rigs available that have not been idle for well over 12 months. And for an incremental 300 Series type rig, there's virtually none available. Thus, incremental rig demand must be met from idle stacked rig inventory. This is significant for several reasons, especially in a market where the incremental rig contract generally reprices the market. First, it places a premium on active hot rigs with experienced crews that have been working together on a customer's drilling program. Customers will not want to give up these rigs. Second, as our industry is forced to reach back into the inventory of stacked rigs, this will require significantly higher capital investment, in particular for rigs stacked 18 months or longer as will be the case on coming reactivations. Hiring the labor is already becoming more challenging, and this will likely become a bigger issue in an improving rig count environment. Higher dayrates and operating margins will be an economic necessity for the drilling contractor to satisfy this demand. And finally, and a point I believe is underappreciated, we expect utilization of true super-spec rigs, that is AC rigs with 1,500 horsepower draw works, 3 pumps, 4 engines and walking to reach 80% or more soon, assuming overall U.S. land rig count steadily improves and accelerates into 2022. There may be other AC skidding rigs or the like available, but the cost of conversion to true super-spec status is in the millions on top of the cost to reactivate, as I just discussed. As I mentioned, term contracts are beginning to appear and become part of the contract discussions with our customers. Today, all of our contracts are short term and expire this year, which we deem prudent given our view on future dayrate improvements. Terming up at current spot market dayrates is not something we're interested in at this time, but we do think it'd be prudent to have some term contracts in place as we move forward into an improving market. The percentage of our total fleet locked up on term contracts will depend on where we are in this cycle, the customer and the type of rig involved. We believe we are very early in this cycle, so I don't expect to see ICD lock up a substantial portion of our fleet on term contracts. We are in some discussions today regarding a couple of term contracts. If we sign these contracts, dayrate will be higher than where spot market dayrates are today, and we're considering only a subset of our total fleet at this time. I want to share a little bit more on our outlook for the balance of this year. It's very important that we return to cash flow neutrality and better as soon as possible. We're doing all the right things. We need more rigs operating and dayrates continuing to increase. As we've discussed, we've been steadily moving towards this goal with improving dayrates and utilization. We expect to be EBITDA positive during the third quarter and continue to target being free cash flow positive as we exit 2021. As we navigate the second half of 2021, we expect the pace of rig count increases to accelerate from current levels as the industry approaches the fourth quarter and continuing as we close out this year. As mentioned, we expect refreshed 2022 capital budgets, the depleted DUC inventory and higher oil and gas prices will span more drilling activity by E&P companies. In this environment, we expect dayrates will continue to increase, especially for super-spec rigs. I expect we'll be bidding dayrates for super-spec rigs before the end of the year to start with a 2, with continued upside during 2022. Based on our current market outlook, I would expect ICD to reactivate another 2 or 3 rigs over the next couple of quarters on top of the rigs we've already reactivated with the opportunity for additional reactivations in 2022. I would be remiss if I did not close with a discussion on our progress regarding ESG. All of our rigs are high line and dual fuel capable and offer environmentally friendly crown lighting and other options for our customers to consider. When our customers require such features, we're more than willing to provide them. Today, approximately two-thirds of our operating rigs are utilizing high line or dual fuel options and about 65% utilize our crown lighting options. We expect utilization of these green package options to rapidly increase as our customers continue to prioritize and focus and plan for operations designed to reduce and eliminate carbon emissions. Also, you should be on the lookout for our inaugural sustainability report, which will be issued later this month. The report will highlight many of the company's efforts towards promoting a more sustainable world. So summing all this up, good things are happening at ICD. We continue to punch above our weight as we recover from last year's unprecedented downturn. We're transitioning to positive EBITDA currently and expect continued improvement on that front, and we're on a pathway for meeting our free cash flow objectives and driving returns for all shareholders and stakeholders. Our financial flexibility has improved since the 2020 downturn, and our management team remains incentivized accordingly to focus on cash flow generation and financial returns over the longer term, with our management team winning only if our shareholders do. Our rigs are in demand and our systems and processes, which support our operations, are best in class. Our rig fleet is young, flexible, and engineered to maximize manufacturing efficiencies for our customers. We're breaking records. We're winning accolades for service and professionalism and working hard to exceed our customers' expectations every day. Our rigs are drilling optimization capable and participating alongside our customers in pursuit of ESG initiatives, firmly implanted with a strong brand and reputation in our target market 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. We continue to gain market share and are excited about our prospects over the next several quarters. So with that, I'll turn the call back over to Philip, so he can walk us through the second quarter 2021 financial results for the company.

Thanks, Anthony. During the quarter, we’ve reported an adjusted net loss of $14.6 million or $2.18 per share and adjusted EBITDA loss of $369,000. Reactivation costs during the quarter were $192,000. We operated 11.8 average rigs, slightly below guidance on the second quarter conference call. The variance relates primarily to our 14th and 15th rigs reactivating in July as opposed to during the second quarter. We expect utilization to increase sequentially by approximately 18% during the third quarter of 2021 compared to our second quarter average, with further sequential increases expected in the fourth quarter of this year. Revenue per day of $16,514 per day came in slightly higher than guidance and increased sequentially based upon increasing dayrates and reduced standby days compared to the first quarter. We did not record any early termination revenue during the quarter. Cost per day of $13,352 per day was in line with guidance. Cost per day excludes approximately $192,000 associated with rig reactivations and $400,000 of unabsorbed overhead costs. These costs were favorable to guidance as cost and efficiency initiatives continue to favorably impact operations. SG&A costs of $4.1 million, which included approximately $900,000 of stock-based and deferred compensation expense was in line with prior guidance, with the sequential increase primarily attributable to variable accounting on stock-based comp associated with increases in stock price at quarter end. During the quarter, cash payments for capital expenditures net of disposals was approximately $2.5 million. These payments included approximately $1 million relating to prior quarter equipment deliveries. There's approximately $3.1 million of CapEx accrued at quarter end, which we expect will flow through during the third quarter of 2021. Our capital budget was based upon a 15-rig fleet. Assuming reactivation of an additional 2 rigs by the end of the current year, we expect 2020 CapEx to increase by approximately $2 million compared to our original budget. Overall, we would expect approximately $4.5 million to flow through our cash flow statement for CapEx, net of dispositions, for the back half of the year. Our backlog at June 30, 2021, stood at $14.8 million, all of which expires in 2021. Obviously, our backlog continues to be below historical levels as most of our rigs are now operating on short-term pad-to-pad contracts, which capitalizes on our view of continued dayrate improvement. Moving on to the balance sheet. At quarter end, we’ve reported net debt, excluding finance leases and net of deferred financing costs of $134.6 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 $6.8 million. Our PPP loan balance does not reflect any potential forgiveness. We submitted our forgiveness application to our lender requesting forgiveness of the entire $10 million loan amount during the first quarter, and following our lenders review, our forgiveness application was submitted to the SBA during the second quarter. Given the nature of the process, we do not know when a final determination or application will be made by the SBA. Now moving on to third quarter guidance. We expect operating days to approximate 1,276 days, representing 13.9 average rigs working during the quarter. This includes reactivation of our 14th and 15 rigs during July as well as a couple of rigs that will have idle time while transferring between customers during the quarter. We expect margin per day to come in between $3,700 and $3,900 per day, representing an approximate 20% sequential increase at the midpoint of this range. We expect revenue per day to come in between $16,700 and $16,900 per day, with many of the dayrate increases on contract rolls, only partially benefiting the third quarter. Cost per day is expected to range between $12,900 and $13,100 per day, lower than the second quarter as we continue to gain efficiencies from a larger operating base. These per day amounts exclude pass-through revenues and expenses. As Anthony mentioned, we continue to see dayrate improvement on contract renewals with most renewals signed during the current quarter, likely not fully benefiting our results until the fourth quarter of this year. So we do expect additional sequential revenue per day improvement after the third quarter and continued efficiency gains at the cost line as more rigs go to work. We also expect to incur an additional $500,000 during the third quarter associated with planned rig reactivations. These costs are not included on top of, in addition to our cost per day guidance. Unabsorbed overhead expenses will be about $600,000 and also are not included in our cost per day guidance. We expect SG&A expenses to be flat with the second quarter with some variability on the stock-based component that is subject to variable accounting. We expect interest expense and depreciation expense to be consistent with the second quarter as well. And for CapEx, again, we expect about $3.6 million net of dispositions to flow through our cash flow statement during the third quarter. And with that, I will turn the call back over to Anthony.

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

And the first question will come from Daniel Burke with Johnson Rice. Please go ahead

Hey, good morning guys.

Hey Daniel.

Anthony, your comment on future reactivations being predominantly 300 Series, and you highlighted some of the capabilities of the rigs -- of those rigs. But I just wanted to better understand. I mean, the thought that incremental reactivations will be 300 Series. Is that a function of the capability of the 300 series? Or is it more realistically a reflection of reduced ready inventory on the 200 Series side?

It's a great question, Daniel. I think it's more a reflection of just where we see demand, large incremental demand in the marketplace. It's also a function of where we can continue to differentiate ourselves in the marketplace amongst our competitors and especially our competitors' rigs. It's where we think we're going to get the most bang for our investment buck as we continue to recover from the effects of what played out last year. Very excited about this class of rig, this is something that obviously hammered a lot in our prepared remarks, but when you think about ICD today, I think this is something that's very underappreciated when people think about the company. Premerger ICD, we needed 2 things. One, we needed scale. And second, we needed bigger rigs, rigs that could prosecute larger developments in U.S. shale and the Sidewinder merger gave us both of those. Unfortunately, as you know, the market has been tough since then. But certainly, as U.S. shale continues to mature, the number of wells on pads, also the lateral lengths are all increasing, which requires a little different tool. And the 300 Series, we think are ideally suited for that. And I think if you look at the uptick in our rig count over the last 9 to 12 months, you certainly see that play out in our contracted rig count.

That's helpful. And then I guess in a way to stay on the topic of reactivations, it looks like from the Q3 guide that the next tranche of two to three rigs that you see is likely to reactivate, probably tilt towards start dates in the fourth quarter. I just wanted to understand if that's correct. And again, what the depth of inquiry levels that you see against your available fleet at this point?

Yes. Consistent with the guide, certainly, what we've seen here in the third quarter, specifically during the months of July and August is the rig count has slowed down. That's consistent. Even though it's still increasing, it's not increasing by double digits, its single-digit type increases week-to-week maybe it's flat another week. And that's consistent with what we saw 3 months ago, what we were seeing last month. But where we get really excited is when we're talking to customers, there's just a significant amount of work that we see that is evolving for start dates in the fourth quarter, really starting in October. And historically, certainly, the last 3, 4 years, we've seen this break in activity as we round out the calendar year. That is not going to happen this year. It's clear with the way the year has played out, with what's happened to commodity prices, the fiscal discipline that our customers have demonstrated over this year that I think they're actually going to pull CapEx from 2022 into this year, get a running start into the new year, and then CapEx budgets next year will be bigger than they were this year. So that's what we're seeing coming. So yes, you're reading it right. We also need to be careful how we pace the reactivations. There's a lot that goes around that. There's a reactivation process itself. There are a few select upgrades that we do on some of these rigs. And then of course, you've got -- you have to hire the crews, you've got to reactivate the rig. You've got to start it up, you've got to mobilize it. So the guide that Philip provided is consistent with being able to do all that in a way that we can continue to operate safely, but also to exceed our customers’ expectations.

Got it. And then maybe a last one, Anthony, if I could coax you into discussing it. The discussion on term being at a premium to spot rates is certainly intuitive at this point in the marketplace. And of course, it would depend upon duration, but what type of premium to spot do you need to induce you into considering a term contract? I mean playing it short has been the appropriate strategy. And given where your cash flow is currently, I think there's a decent argument to be made for staying on the spot side of the market. When do you make that shift?

Yes. I think it's going to be driven by your outlook, obviously and I think you can tell from everything that we've said today, we're very bullish about the outlook certainly next year. We believe the dayrates will continue to increase, not just from a supply demand standpoint, but just from an economic necessity standpoint. So as we sit down and evaluate those opportunities, we're going to think about the type of rig, the relationship with the customer, is the customer going to use the full capabilities of the rig that's in discussion or not. Obviously, we're going to have a view on where we think rates will be over that term period, whether it's six months, 12 months. And think about it from a, I would say, from a blended average type perspective. And that's why I would say, if we were to do a term contract today, it would obviously be at rates higher than where spot market is today. If you do that right, the average of that rate over the term is going to be consistent with where you see dayrates, spot market rates moving over that period as well. I guess what I wanted to highlight in the call today was just that up until really the last couple of months, we've not had customers reach out and want to have that conversation. And that's certainly been a change here over the last couple of months.

Appreciate all the comments guys. I’ll leave it there. Thank you.

Okay, thank you, Daniel.

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

Okay. Thank you, Chuck. Guys, as we end the call, I'd like to say thank you to everyone for joining us. Also, I want to say thank you to all the ICD employees, former and current, who have contributed to our success over the years as we celebrate our 10th anniversary here this year. I also want to thank them for their professionalism and focus on our customers. The results of those efforts and that focus are evident today. As just this morning, we were awarded for the third year in a row, Energy Research Point's award for service and professionalism. And I'm really proud of that achievement, I just want to say thank you to all of our employees for that. Also, I want to make our investors aware that ICD will be presenting at EnerCom's 26th Annual Oil and Gas Conference in Denver occurring August 15 through the 18th. So here in the middle of the month. We look forward to speaking to you again on our next call. I hope to catch up with you before then as well. Thank you again, everyone, for your interest and support in ICD. With that, we'll end the call here.

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