Independence Contract Drilling, Inc. (ICD) CEO Anthony Gallegos on Q1 2021 Results - Earnings Call Transcript

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Independence Contract Drilling, Inc. (NYSE:ICD) Q1 2021 Earnings Conference Call May 4, 2021 12:00 PM ET

Company Participants

Philip Choyce - Executive Vice President and Chief Financial Officer

Anthony Gallegos - President and Chief Executive Officer

Conference Call Participants

John Daniel - Daniel Energy Partners

Daniel Burke - Johnson Rice

Operator

Good day and welcome to Independence Contract Drilling Incorporated First Quarter 2021 Financial Results and Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded.

I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead, sir.

Philip Choyce

Good morning everyone, and thank you for joining us today to discuss ICD's first 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 of our non-GAAP measures.

And with that, I'll turn it over to Anthony for opening remarks.

Anthony Gallegos

Hello everyone. Philip will go through the details of our financial results for the first quarter of 2021 in a couple of minutes. In my prepared remarks today, I want to focus on three things: A brief update on our recent quarter, the acceleration of utilization in day rate momentum we're experiencing, in particular within the last 45 days; and update you briefly on our progress regarding ESG. We reported as EBITDA loss, even though we continue to add contracted rigs. Reactivation cost impacted our results by approximately 1.1 million during the quarter. The cold weather freeze that gripped Texas Back in February impacted our results only slightly. It delayed the start up for one rig, and we had another rig going on lower force majeure rate for a short period of time.

Our financial results continued 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. Looking forward, we are confident that the past two quarters represent the trough for us as our industry continues to recover from the impacts of the COVID pandemic. Phillip will go through guidance in a minute, but as we sit here today, we have a pretty good line of sight on recovery of positive EBITDA this year, with our goal still intact of exiting the year generating free cash flow.

Overall, liquidity at quarter’s end stood at 32.2 million. During the quarter, we did selectively access our equity line of credit and ATM programs, raising approximately 1.5 million in gross proceeds at an average price of $4.85 per share. Overall liquidity consisted of 5.4 million of cash on hand, 7.7 million of availability under our undrawn revolver, [50 million] under our term loan accordion, and 4.1 million remaining available under our equity line of credit.

Now on to the business, contracting activity and day rate improvement during the first quarter were positive. Overall, we operated 12 rigs during the quarter averaging 10.3 rigs during the quarter. Renewals included day rate increases across the board with some rigs receiving rate increases of 1,000 or more per day. More importantly, as I mentioned earlier, positive utilization and day rate momentum for ICD has continued to accelerate during the past 45 days.

Currently, we plan to reactivate an additional four rigs during the second quarter at the highest dayrates we have contracted since the onset of the pandemic. And in the process, we are increasing our exposure to larger multi-rig clients. One of these rigs will replace our 1,000 horsepower rig based upon changing customer requirements for larger rig. The rig has performed exceptionally well and we have some opportunities for re-contracting this rig, but it is not included in our second quarter exit forecast of operating rigs.

Of the four plan reactivations, we have two contracts in hand and we're finalizing contracts for the remainder. Overall, we expect to exit the second quarter with 15 rigs operating, consistent with our 2021 business plan, and we believe there's upside to that. I would expect that these 15 rigs, 7 will be working in the Permian, 5 in the Haynesville or East Texas, and 3 in South Texas and Eagle Ford.

All of this is critically important for ICD strategic focus on a go forward basis. So, I want to provide some more color on what we see as the drivers for the contract and date rate acceleration we are seeing in ICD. When the industry was coming off the historic bottom beginning in the third quarter of last year, contracting opportunities were few and far between and we could not be very selective on which contract opportunities we secure.

If you'll recall, rig count had bottomed at 244 rigs working in the lower 48 during August of last year, and currently sits at 439 rigs as of April 16, 2021. As our industry has continued to heal from the pandemic, we've been able to be more selective, even turning down opportunities either because the day rate was too low, the contract opportunity didn't justify the CapEx or the geographic or customer fit wasn't right. A specific goal we established for 2021 was to re-establish more multi-rig clients, like we had pre-pandemic, put more rigs with customers who have larger and more extensive drilling programs.

The contracts we have signed since quarters end are significant steps toward achieving that goal. In particular, during the first quarter, we put a second rig with a client in Midland basin, and after the close of the quarter, we signed multiple contracts and received commitments from former customers that increases our number of multi-rig clients further from two to four and we're working on expanding what will be our fifth multi-rig client here during the second quarter.

At ICD, we love all of our customers and the efficiencies that can be gained by working multiple rigs for the same customer undeniable. With respect to the market, the overall rig count has ramped up nicely during the first quarter exceeding most analyst expectations. And we expect that to continue during the remainder of this year, but likely at a more moderated pace.

In that type of environment, we believe there will be additional opportunities for rig reactivations for ICD later in the year. But I want to emphasize we will not proceed reactivations if the rates and terms and customer do not justify the incremental capital outlay. This view is supported by our opportunity set today. It's worth highlighting that ICD has continued to reap the benefit of outsized market share gains.

Since the bottom, our operating rig count has increased well over 300%, compared to an 80% increase in the overall market. That is because some of our incremental reactivations are not the result of our customer adding a rig, but rather an ICD rig displacing a competitor's rig. In fact, during the second quarter ICD will be replacing rigs from three of our very largest competitors. These placements were not secured based on price, meaning we didn't undercut our competition to knock them out of the saddle.

In fact, these are the highest dayrates in our fleet today, consistent with the higher end of the day rate range you hear drillers talk about today when describing spot market pricing. The customer’s decisions in these cases were driven by relative performance and capabilities of the competing rigs and the customer’s preference were working for ICD.

Yes, you have to be competitive on day rate, we all know that, but the point I'm trying to make is we are building on the strong brand, which we have, our operational performance and our rigs capabilities to increase market share in intentionally penetrating more large public and private independent oil companies in the process.

This is important for outlook, as these are the EMPs that will continue to add rigs as we work toward year-end 2021 and especially as CapEx budgets increase in 2022 and likely beyond in response to continued improved commodity price environments for oil and natural gas.

I think also there's a bifurcation underway in the rig market day that is driving ICD’s utilization outperformance compared to the market. Previous bifurcation in our industry was based on rig capabilities. 10 years ago, it was AC versus SCR mechanical. Then it evolved to walking versus skidding, and more recently three before mud and generator configurations, and of course technology.

Today, in a lower rig count environment, the current bifurcation is being driven by contractor quality, sophistication, and financial wherewithal. Customers can take for granted that [your rig] meets their specification. But many of today's EMPs have certain specific requirements in terms of systems processes, technology, and overall competency of their service providers.

The consolidation that is happening within our customers, the EMP community appears to be accelerating this move to a smaller subset of the overall drilling contractor community being relevant, and we're glad of ICD to be part of this cadre, which will continue to drive the provision of super stack PAT optimal rigs working in U.S. Shale.

You can see all this in the overall contractor rig counts with more market share gains and creating primarily to the most sophisticated land drillers. This is important for ICD as we've been strategically positioning ourselves to participate in this evolving market dynamic, except for 1,000 horsepower AC rig, all ICD rigs are equipped with four generators and three mud pumps, and all have the platforms that deploy technology when required.

I'm particularly excited about the recent market penetration and contract wins for our 300 series rigs. If you recall, these rigs came to us in the Sidewinder Merger, and are specifically designed for extended reach, long laterals, and where our customers want to use larger or high torque drill strings. Many of these rigs are capable of racking 29,000 feet of 5-inch drill pipe and 25,000 feet of 5.5-inch drill pipe.

They meet in many cases exceed our customer's requirements for their most complicated extended reach wells. Rigs with these specifications are few and far between within the U.S. land fleet. As you would expect, these rigs are in high demand and command the highest dayrates. The reality is that until recently, this is the first time since the Sidewinder Merger in late 2018 that we've had the opportunity to market these rigs across our customer base into an improving market where our customers were not in the process of reducing rig count.

And I think that fact is supplemented by the company's strong operational performance marketed by top notch sales and marketing team. Since the trough last year, we deployed three of these rigs and with contracts in hand we'll be deploying several more during the second quarter and expect there'll be additional opportunities to deploy more during the second half of this year while continuing to feel and respond to strong demand for a 200 series rigs.

In other words, right now, ICD is seeing increasing demand for our 300 series rigs and this is important for our company, our employees, and our shareholders. Whatever their preference, ICD has the right rigs for customers today, including those EMPs that demand plenty of hydraulic horsepower, powered by generating capacity to run all three mud pumps simultaneously, and when necessary, deploy technology and utilize extreme drilling, racking, and setback capacity.

We've accomplished this with minimal cash outlay, primarily through our strategic merger and by employing unused equipment thereby maximizing our returns in this challenging environment.

Now, on the dayrates, in light of the continued increase in demand for drilling rigs in ICD’s operational performance, dayrates continue to improve while we are nowhere near where we need to be to have a healthy drilling contractor industry. We have been able to make progress during the first quarter and especially since quarters end. We've been able to increase dayrates up to $1,000 a day or more on contract renewals. And two of these contracts I just referenced are dayrates in the high teens before adders, which is a significant improvement over spot market pricing last year.

For the most part, these contracts are short, pad to pad type work, which is fine given our outlook for rig demand. We don't want to lock up at today's rate when the outlook is so strong. The only downside is the contracts won't show up in our contract backlog statistic as we only count contracts with durations longer than six months.

As these rigs and re-pricing on renewals will get layered into the fleet over the second quarter, they won't possibly impact our financial results fully until the third quarter. Also something that probably gets overlooked are contract terms, which are also improving in particular over the last 45 days. The incidental type charges that are typically the responsibility of our customer can find their way onto the contractors side of the ledger in very soft markets. And this happened to us coming off the rig count bottom.

In the more recent contracts we've signed, we've been successful in pushing these types of incidentals back to our customers. The cost of which add-up and are meaningful for drilling contractor margins, especially at low dayrates. Another positive data point we are seeing is more competition from customers for the same rig. This is also part of the dynamic, which we saw accelerate after the first quarter close. This is an important fact because as we think about the lower 48 rig supply today, we're very confident that most of the easy, cheap, low-hanging, easy rig reactivations in the U.S. land rig fleet have occurred.

We believe industry-wide reactivation costs are higher for rigs stacked over 9 months to 12 months thereby requiring higher dayrates to generate economic returns as rigs return to active duty. In addition, there's a clear preference by customers to take a hot rig over one that's been stacked for 9 months plus. In other words, it is an economic necessity that dayrates must be higher due to more demand for fewer hot rigs and in order to justify the spend that any drilling contractor must make in order to bring rigs out that have been stacked for almost a year now.

If the rigs have to be upgraded than the contract value that should be required is yet even more. I also think the supply of the highest specification equipment is near the inflection point where pricing power increased to the drilling contractor. If you think about a true pad optimal super spec rig, I'm talking about AC, 4 engines, 3 pumps, 1,500 horsepower, with 20,000 feet or more racking capacity and importantly walks, that is what our customers want.

They're only about 450 or so available in the U.S. land rig fleet today, unless very significant CapEx dollars are [spent]. And the supply of 300 series spec type rigs is even lower than that. And we believe we're getting close to full utilization of that supply. Our best estimate is that utilization of the super spec fleet today is in the neighborhood of 65%, and with 300 series type utilization is meaningfully higher than that.

So, we believe the signs are very positive for meaningful day rate progression during the back half of this year, especially given the small relative percentage of spin, which the rig now represents in our customers overall AFE well cost.

I'd like to close by addressing ICDs efforts on the ESG front. At ICD, we're focused on doing our part toward the industry's effort. Regarding the E and ESG, all of our rigs are dual fuel capable and many of them are employing this carbon reducing technology today by using natural gas in combination with diesel as feedstock for our generators.

Today, we have rigs powered by electricity from the utility grid. And of course, many of our rigs are burning some form of clean burning natural gas. Outfitting our rigs, and running them in this manner not only results in cost savings for our customers, but also significantly minimizes and in some cases completely eliminates a 100% of the pollution at the pad site, compared to running for generators on a job location, which is how rigs typically received their electrical power.

Of course, we're always looking for other customers that are willing to undertake the same strategy. While I believe our industry has done a lot of good work on this front over the years, we are excited about our prospects as an industry to continue addressing these challenges. I would be remiss if I did not point out that many of our executives [MBO objectives] are tied to environmental and sustainability objectives.

On the social front, we're making arrangements to continue to give back to the communities where we work during the summer and fall and planning other initiatives involving further charitable efforts here in Houston, where our corporate headquarters is based. I would like to point out that we have a very robust social media presence and I invite everyone to follow us on Facebook, Twitter, and LinkedIn to hear about the good things ICD is doing out in the field and in our community.

Regarding the GNESG, we've been very forward leaning on the governance front historically, including tying a substantial portion of executive comp to quantifiable measures, which are closely aligned with our shareholder’s interests. At the end of February, ICDs Board established compensation metrics for 2021, and this year 100% of our executive team's long term incentive compensation is performance based, and therefore 100% of risk.

I think this is another fact that makes ICD very unique in oilfield services. Still another measure we've taken to further align management's interest a 100% with that of our shareholders is tying TSR metrics, not only to a driller or an oilfield service peer group, but also to a broader market index across all industries. I point all this out because in a returns based world, our shareholders should know that ICD is pulling all the levers available to drive returns and align ourselves with them. And over time, I expect to see these results manifest themselves in better financial returns and free cash flow generation.

We just need a couple more quarters to properly assemble the chess pieces. So, summing all this up, there are a lot of good things happening in ICD today. We continue to punch above our weight as we recover from last year's unprecedented downturn. We're on a pathway to free cash flow and driving returns for all of our shareholders. 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 long-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, winning accolades for service and professionalism, and working hard to exceed our customer’s expectations every day across our fleet in their offices. Our rigs are drilling optimization capable and participating alongside our customers in pursuit of ESG initiatives.

We're 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.

With that, I'll turn the call back over to Philip so he can walk us through first quarter 2021 financial results for the company.

Philip Choyce

Thanks, Anthony. During the quarter, we reported an adjusted net loss of $16.4 million or $2.64 per share, and an adjusted EBITDA loss of $2 million. We operated 10.3 average rigs consistent with guidance provided on our prior conference call. We expect utilization to increase sequentially by over 20% during the second quarter of 2021, compared to our first quarter average, with further sequential increases expected in the back half of the year.

Revenue per day of $15,465 [fell sequentially] based upon one rig operating on a standby basis for most of the quarter, and the expiration of our final legacy pre-pandemic contracts. Revenue per day was slightly higher than guidance, principally due to lower standby days, compared to the expectations. We did not record any early termination revenue during the quarter.

Cost per day of $12,663 was higher than guidance, primarily due to lower than expected standby days, and to a lesser extent, perhaps $300 per day or $270,000 in the aggregate of costs associated with a combination of the February freeze and discrete repairs during the quarter. Cost per day excludes $1.1 million associated with rig reactivations and $500,000 of unabsorbed overhead cost during the quarter. Those costs were slightly favorable compared to guidance.

SG&A costs of $3.7 million included $700,000 of non-cash compensation expense. Cash SG&A expense increased sequentially from the fourth quarter associated with incentive compensation accruals for the new fiscal year, as well as seasonal year-end audit and related matters.

During the quarter, cash payments for capital expenditures net of disposals was approximately $1 million. These payments included approximately $900,000 relating to prior year equipment deliveries. There's approximately $1 million of CapEx accrued at quarter-end, which we expect will flow through during the second quarter of 2021.

Overall, right now, our capital budget for 2021 remains unchanged. Our backlog at March 31 stood at $12.1 million, all of which expires in 2021. Obviously, our backlog is substantially below historical levels, as most of our rigs are now operating on short-term pad to pad contracts to capitalize on our view of continued higher dayrates throughout 2021.

Moving on to our balance sheet, at quarter-end we reported net debt excluding finance leases, and net a deferred financing costs of $132.1 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 $7.4 million. Our PPP loan balance does not reflect any potential forgiveness.

During the first quarter, we submitted our forgiveness application to our lender requesting forgiveness of the entire $10 million loan. Our forgiveness application, including our assessment of the necessity for and qualification for the loan will be reviewed by both our lender and the SBA, and given the nature of the process, we don't know exactly when a final determination on our application will be made.

Anthony mentioned at quarter-end, we had total liquidity of $32.2 million. Looking at the sufficiency of this, we have reported an EBITDA loss for the past several quarters and are generating negative free cash flow. I'll go through guidance in a moment. But as Anthony mentioned, we are moving in the right direction. We elected to pick the payment of our April 1 interest payment, which was [indiscernible] under our term loan facility, which increases projected liquidity.

We also expect our revolver borrowing base will continue to increase as we continue to reactivate rigs and our operating rig count and AR balances increase. I still believe assuming continued moderate improvements in our operating rig count the back half of the year and steady improvements and revenue per day, we can approach free cash neutrality late in 2021 and meaningfully improve on that in 2022. Given the levers available to us to pull at this time, we're comfortable with our financial liquidity position.

Now moving on to second quarter guidance. We expect operating days to approximate 1,130 days, representing 12.4 average rigs working during the quarter. As Anthony walked-through, we expect to exit the second quarter with 15 rigs operating in-line with our 2021 business plan. We expect margin per day to come in between $3,000 and $3,200 per day, representing an approximate 11% sequential increase at the mid-point of this range.

We expect revenue per day to come in between $16,300 and $16,400 per day, and cost per day to come in around $13,200 and $13,400 per day. Again, we don't expect any standby days will affect these statistics during the second quarter like they did in the first quarter. These per day amounts exclude pass through revenue and expenses.

As Anthony mentioned, further day rate improvement from recently signed contracts will primarily benefit the third quarter onwards. So, we do expect some additional sequential revenue per day improvement after the second quarter, and continued efficiency gains of the cost line as more rigs go to work.

We also expect to incur an additional $1.3 million associated with the four planned rig reactivations and the replacement of the 1,000 horsepower rig during the quarter, and $600,000 on unabsorbed overhead costs during the quarter. These costs are not included in and on top of in addition to our cost per day guidance.

We expect SG&A expense to approximate $4 million. Included in this estimate is approximately $900,000 of non-cash compensation expense. The sequential increase in non-cash compensation relates to full quarter expensing of at-risk performance-based compensation, which only partially affected the first quarter of 2021. These awards are subject to variable accounting, so the ultimate amount of expense will be based on our stock price at quarter-end and progress towards performance goals.

We expect interest expense and depreciation expense to be approximately 3.8 million and 10 million, respectively and tax expense to approximately $100,000. For capital expenditures, we expect approximately 2.3 million to flow through our cash flow statement during the second quarter.

And with that, I will turn the call back over to Anthony.

Anthony Gallegos

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

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] And the first question will come from John Daniel with Daniel Energy Partners. Please go ahead.

John Daniel

Hey guys, good morning. Hopefully you can [indiscernible].

Philip Choyce

Good morning, John.

Anthony Gallegos

How are you?

John Daniel

I'm good. I just got one question. You noted the customer requirements on rig specs are increasingly, you know, call it a gating item, maybe in terms of the rig contracting process. And I'm just curious as that continues to evolve, how will that limit? Do you think any consolidation opportunities amongst some of the smaller private land drillers?

Anthony Gallegos

Yeah, John, thank you for the question. So, I think there will continue to be a need for what we would refer to as pad optimal super spec type equipment. What I was trying to illuminate in the comments really was a subset of the market, a niche that we think is going to continue to grow. Obviously, it's very exciting for us, because we believe we have the equipment to target that. And you know, one of the dynamics that's driving it are bigger pads. I think also the consolidation that's happening within our customers. And you think about the checkerboard acreage that's out there, how they're able to piece things together, it gives them the opportunity to leverage that fixed cost on one pad as opposed to building multiple pads and maybe access more of the reservoir than they would have beforehand. And in order to do that, they're going to need a different type of rig one that can drill a longer lateral, maybe a bigger bore or both. And the punch line is and the point I was trying to make is, the 300 series rigs that we have are ideally suited for that. And I think the fact that you're seeing that evolve right now in the marketplace, and we would expect that to continue is very exciting for us. And that was really where I was trying to go with that.

John Daniel

Fair enough. Okay, appreciate that. And then the last one would be just, any thoughts observations on supply chain? What issues are facing you guys right now? Just any broad commentary would be appreciated.

Anthony Gallegos

Yeah, you know, we spend a fair amount of time talking about that. You look around us, you know, in our private lives and others we've all been impacted in different ways. Some of it just because of the pandemic, other computer chips, and stuff like that. But at ICD as a company, you know, we've continued to roll with the punches, not aware of any issues in terms of supply chain access to equipment, stuff like that that's hindering our ability to service our customers today or to continue to prepare the company to, you know, even add rigs to these customers. So, so far, knock on wood, it's not an issue for us.

John Daniel

Okay. That's good. That's all I had guys. Thank you for your time.

Anthony Gallegos

Thank you, John.

Operator

The next question will come from Daniel Burke with Johnson Rice. Please go ahead.

Daniel Burke

Yeah, let's see. Good morning, guys.

Anthony Gallegos

Good morning, Daniel. How are you?

Daniel Burke

Fine. Fine, Anthony. So, Anthony, last quarter, you talked about sort of as your rig count got to the mid-to-upper teens, considering taking almost an intentional pause – and I think that reflected the thought that activation – reactivation costs were going to rise, and maybe the rates weren't there to support that yet. I mean, does that [lead] to some optimism here this morning on rates certainly. So, we do still see an intentional pause or is the strategy a little different as you sit here today?

Anthony Gallegos

No, I think the one thing that maybe has changed slightly from the last time we talked is, we have seen some pretty good day right momentum. Obviously, we're coming off a low base, as I said in prepared remarks. We're not anywhere near where we need to be, but certainly, you know, every renewal that we've had, and certainly every new contract that we've signed, since the last quarter’s call has been at higher dayrates. And that ranges from, you know, minimum $500 a day to in some cases over $1,000 a day. So that certainly has been a positive development.

As we look at the fleet as we consider reactivation costs, and stuff like that, you know, we're very comfortable and, you know, the number that we put out [a 15], by the end of the second quarter, we've talked about that now for two quarters. You know, maybe there's a couple more, depending on where the market is in Q3, Q4 that we might end by the end of the year. But I don't see us running, you know, very far beyond that number.

Unless and until we continue to see this day rate improvement that we're talking about Daniel, but look, everything that we see in the market, certainly what we're hearing from our customers, what's happening with the commodity, the macro picture is, as far as we can tell, is very supportive of, you know, continued increases in rig count, albeit, it's probably more moderated in Q3, and Q4 as it has been in the first four months of this year. But it really sets up a pretty good 2022 in our mind, especially as capital budgets get recharged.

In the early part of the year, I would expect to see an increase in demand very similar to what we saw in 2021. It just, like I said it's going to be slower than any of us want, but the punch line for ICD is that assuming using those assumptions, we will continue to add rigs on a very measured pace into what we believe will be an improving market for next – the next several quarters to come, Daniel.

Daniel Burke

Got it. And I guess then my follow up is, as you guys develop better line of sight and better conviction around getting to, sort of that free cash break over point by the end of this year. I mean, you've used you’ve used equity, you’ve used ATM pretty effectively here over the last year. I mean, is that still part of the strategy as you look forward from today?

Philip Choyce

Daniel, I think we will be opportunistic when we use those types of things. I think we've done a good job so far. You saw what we did in the first quarter. It wasn't, you know, significant magnitude, but it was at favorable prices. So, we'll look at that as you know, a way to, you know, [indiscernible] take advantage of the market when it's available to us.

Daniel Burke

Makes sense. I'll leave it there guys. Thank you for the time.

Philip Choyce

Thank you.

Operator

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, sir.

Anthony Gallegos

Okay, well thank you, [Chuck] for that. Guys, we want to thank you all for joining us today for our call. Before I sign-off, I'd like to thank the hundreds of hard work and dedicated employees at ICD for their service and sacrifice. Also, I'd be remiss if I didn't mention that here over the summer at ICD we're going to be celebrating our 10th anniversary, our 10th birthday.

So, I want to thank all of the ICD employees, former, and current who've contributed to the company's efforts over these years. With that, we look forward to speaking to you again on the next call and hope to catch up with you before then as well. Thank you, everybody. We'll end the call now, operator. Thank you.

Operator

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

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