Independence Contract Drilling, Inc. (NYSE:ICD) Q2 2020 Earnings Conference Call August 4, 2020 ET
Philip Choyce – Executive Vice President & Chief Financial Officer
Anthony Gallegos – President & Chief Executive Officer
Conference Call Participants
Kurt Hallead – RBC Capital Markets
Ryan Pfingst – B. Riley FBR
Daniel Burke – Johnson Rice & Company
Good morning. Welcome to Independence Contract Drilling Second Quarter 2020 Conference Call. All participants will be in listen-only mode [Operator Instructions] Please note that this event is being recorded.
I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead.
Good morning, everyone, and thank you for joining us today to discuss ICD’s second quarter 2020 results. With me today is Anthony Gallegos, our President and Chief Executive Officer.
Before we begin, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company’s earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for our full reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures.
With that, I’ll turn it over to Anthony for opening remarks.
Thanks, Philip. Philip will go through the details of our financial results for the second quarter of 2020. In my prepared remarks, I want to talk about the world which evolved during the quarter, and the actions which we’ve taken to address those challenges, offer some current perspective about the rig market today and outline our outlook for the next couple of quarters.
Without a doubt, during the second quarter, our industry experienced the full effects of the unprecedented downturn resulting from oil and gas demand destruction caused by COVID-19. I call this unprecedented because although our industry has experienced very difficult downturns in the past, most recently, 2015 to 2016 and the 2008 to 2009 periods, this one is very different.
First, the pace of activity decline is unprecedented. From February 25 to July 23, the U.S. land rig count dropped from 790 rigs to 251 rigs, a 68% decline in just a few months. In addition, COVID-19 didn’t hit when our industry was in an uptick, the rig count already had been declining throughout 2019. And as a result, contract drillers, including ICD and all of our competitors, did not enter this downturn with large contract backlogs to insulate us as we had in previous downturns.
All this makes the current economic climate extremely difficult, and we at ICD have acted swiftly and decisively to pull levers available to us to rationalize our cost structure and to maximize financial liquidity. As events unfolded in the second quarter of this year, we knew that ICD’s contract utilization would decline along with our competitors, and we felt we needed to brace for a steep and prolonged slowdown.
We took immediate and significant action to preserve and enhance liquidity, which necessitated canceling CapEx projects, reducing cost, shrinking our support organization and raising capital where possible. In the process, we right-sized the organization for a lot less activity compared to what we expected just a month earlier. Meanwhile, preserving our ability to provide the safest and most efficient operations possible to our customers.
During our last earnings call, I explained our cost mitigation efforts, including salary and headcount reductions all the way to the Board level. So I won’t go through that again. But you can see the immediate impact of these changes in our reported results for the second quarter.
Our operating cost per day declined to below $13,000, a 13% sequential decline. And our run rate SG&A, after excluding furlough and professional fee expenses associated with onetime corporate activities to increase liquidity, sequentially fell 34% quarter-to-quarter. In fact, as a result of these cost-cutting initiatives, during the quarter and in spite of the significant decline in operating activity, we were able to produce a 35% sequential increase in reported margin per day.
On the CapEx front, we halted everything but maintenance items. And as a result, new CapEx during the quarter fell to approximately $500,000. And as I mentioned on our previous conference call, in addition to maintaining the safest and most efficient daywork drilling operations, maximizing financial liquidity during unprecedented times like these is paramount.
And during the second quarter, ICD made tremendous progress in this regard. Overall, we implemented measures that increase the company’s near-term liquidity and reduce near-term non-operating expenditures by over $20 million on a combined basis. These efforts included: securing a $10 million loan pursuant to the Payroll Protection Program under the CARES Act, which is being used to fund permitted expenses under the referenced act.
Based upon recent changes in the PPP regulations, we currently estimate $5 million of these loan proceeds will be forgiven. In addition to providing much needed liquidity to fund ongoing operations during these unprecedented times and enabling us to retain key personnel, the loan also enabled several additional liquidity enhancing events, which we executed on during the quarter.
We worked with our term loan lender to permit us, at our election, to pick one quarterly interest payment. We also successfully extended the due date on the final payment obligation pursuant to the Sidewinder merger until the middle of 2022. Combined, these two modifications pushed out approximately $6 million in required future non-operating expenditures.
And we successfully raised approximately $7.3 million of gross proceeds pursuant to an ATM offering through the end of the quarter, issuing shares at a gross selling price of $6.15 per share, well above the average VWAP during the period, the ATM has been in place. At quarter end, we had approximately $3.7 million of additional capacity under this ATM program.
During the quarter, we also repaid all outstanding borrowings under our revolving credit facility. Availability at quarter end was approximately $9 million. But as mentioned in our prior call, as our rig count declines, the borrowing base and thus, our availability to borrow under this facility will decrease until our AR balances begin to increase again. Thus, although the facility will support working capital investments when rigs return to work, it is not expected to be a significant source of liquidity to fund non-operating expenditures or operating shortfalls.
Overall, as a result of these efforts, we exited the quarter with total liquidity of $41.6 million, an increase of $8.2 million compared to March 31, 2020, including cash and availability under our term loan accordion and revolving line of credit. At June 30, even after repaying all outstanding borrowings under our revolving line of credit, our cash balance stood at over $17 million, representing a $7.6 million increase compared to March 31, 2020.
Now I would like to offer some perspective about the current rig market. As you saw in our press release earlier today, ICD’s contracted rig count continued to decline as the industry slowdown accelerated during the second quarter. As I mentioned during our first quarter conference call, it has been the case in the current market that when a rig’s contract is up, the operator returns the rig regardless of the rig’s operating performance. And this trend continued throughout the second quarter and into the third quarter. Although we are starting to see a few green sheet opportunities from private operators, I will get to in a moment.
We exited the first quarter with 17 rigs operating, and we ended the second quarter with 5 rigs under contract and operating across the Permian, Eagle Ford and Haynesville Basin. Throughout much of the second quarter, there was essentially no demand for incremental rigs because of the slowdown in overall activity. Essentially, all E&P operators have reduced their contracted rig fleet in line with overall E&P CapEx reduction efforts. In spite of this, ICD was able to negotiate a 1-year extension for one of our rigs in the Haynesville.
However, for the most part, throughout the last 5 months, they’re simply have not been opportunities to supply incremental rigs to customers as they have all focused on decreasing their overall rig activity levels. However, starting in late May and continuing through July, we began having constructive conversations with a handful of customers regarding possible rig adds later this year as oil rate bounded and stabilized above $40 a barrel. These customers include existing and prior customers of ICD, and also operators that would be new customers for us.
Generally, these are private operators, but one is a very large independent. For example, we are at the contract execution phase for an 8-well program in the Permian for one of our stacked rigs out there. Thus, we are optimistic that the third quarter will be the trough for ICD’s operating rig count, and we expect to begin adding operating rigs late third quarter and during the fourth quarter. However, forward visibility for us and our customers is very difficult, and nothing is certain in these unprecedented times.
Looking back over the last 15 months, it’s now obvious that the current slowdown really began in late 2018 as oil prices began to soften from the mid-70s in the summer of that year, dropping to the mid-40s in December 2018 before increasing again for the first 4 months of 2019.
Of course, the steep and subsequent decline in oil prices hit work speed during the second quarter of this year because of the virus and its effect. Because of that, ICD never had the chance to show what post-merger ICD 2.0 can do with its larger operating fleet, and expanded footprint in key operating basins as a result of our strategic combination, which closed in October of 2018.
I point this out because as we talk about current marketing activity for ICD, some of the discussions we are having are with customers that we haven’t worked with before. We are in these discussions today because of our high-quality rig fleet, industry-leading systems and processes, larger operating fleet and strong reputation for providing excellent customer service.
Before our 2018 strategic combination, we liked the rig fleet size to have meaningful conversations with a select group of very active operators. Our larger high-specification rig fleet and very good operational performance today warrants an operator’s attention and therefore, enables us to have constructive conversations with a very large independents and super-majors that we have not worked for previously.
When I evaluate the competitive landscape today, I feel like all drilling contractors are starting from the same place, meaning we all have plenty of high-specification rigs available. And as a result, I believe ICD can grow market share with these active operators as they begin to put the pieces back together and eventually increase the contracted rig fleets over the coming years.
Our operations and marketing teams are doing a fantastic job executing on our mission and telling our story. I’m very excited about these prospects in this arena. We just need some help from the commodity markets.
On the day rate front where the discrete rig contracting opportunities that present themselves over the next few quarters, we expect pricing to be difficult. Right now, I still don’t believe there’s an established spot market, and we probably won’t see a reliable one developed for a quarter or two. However, I think because of the concentration of high-specification rigs in the hands of a few large drilling contractors, we will see pricing for that class of rig rebound quicker than you might expect starting next year.
I expect, for the most part, industry players in the high-specification rig market will exhibit pricing discipline as the market begins to improve, although I expect there may be instances driven by a particular requirement or need when a drilling contractor may propose pricing that is below what market indicators would imply.
Now I would like to close with some comments about the revised outlook for the company. Customers generally tell us that oil prices above $50 a barrel and gas prices above $2.85 are needed to grow in sustained drilling activity. Global oil producers have been aggressive in their efforts to remove oil supply from the market and oil prices have stabilized above $40 a barrel as a consequence.
U.S. operators are bringing production back online, which may create near-term headwinds depending on the pace of growth in the U.S. and global economies, which will soak up excess oil inventories and will be driven, for the most part, by when and how fast economies reopen and if they can stay open.
The natural gas market was expected to benefit from reductions in associated gas derived from shut-in oil production, but that market has experienced headwinds as E&Ps have restarted shut-in oil production. And as a result of the impacts from reduced LNG exportation, which has resulted from the slowdown in global economies and a reduced need for natural gas and foreign energy markets as a consequence.
We’ve recently seen a bottoming in natural gas prices, and I think everyone expects gas prices will strengthen as we exit the inventory build period and see draws begin later this year as heating demand returns, combined with continuous improvement in global economic activity and a rebound in the LNG market.
I believe there will be some contracting opportunities around the margin during the balance of this year in the Permian and to a lesser degree, in the Eagle Ford. However, I expect overall activity levels for drilling to eventually bottom and more or less move sideways until we see 2021 drilling and completion budget money begin to get spent against the backdrop of improving economic activity and strengthening commodity prices.
Based on our discussions, which have continued over the last couple of months, I do expect to see ICD’s utilization tied to gas activity begin to increase later in the third quarter and continuing through the fourth quarter. This timing has slipped to the right by a few months with the reasons I just noted. Also, expect we will have some wins in the oil shale basins, but I do not expect to see a lot of increased activity in any of them for the industry during the balance of this year. Rig markets will remain challenged as we navigate the rest of the year, and I think everyone knows that.
So summing all this up, I believe ICD has pulled and will continue to pursue the levers available to the company to help us weather the current storm. The management team are [indiscernible] and are incentivized accordingly to focus on cash flow generation and financial returns over the longer term. Times are tough, but the ICD team remains motivated and energized.
Our systems and processes, which support our operation, are best-in-class and our rig fleet is young, flexible and engineered to maximize manufacturing efficiencies for our customers. Our rigs are drilling optimization capable and ready for the continued focus and actions by our customers regarding ESG concerns and mandates once their focus returns to drilling oil and gas wells.
We are firmly implanted with a strong brand and reputation for providing the safest and most efficient contract drilling services in North America’s most prolific oil and gas producing regions, which reside in Texas in the contiguous state.
With that, I will turn the call back over to Philip, so he can walk us through the financial results for the company.
Thanks, Anthony. During the quarter, we reported an adjusted net loss of $11 million or $2.73 per share and adjusted EBITDA of $4 million. With respect to the other items during the quarter, rig utilization of 32% came in slightly below guidance provided on our prior quarter conference call, primarily due to early termination of a rig during the quarter.
Revenue per day of $19,741 came in slightly higher than guidance based on contract fleet mix and strong operating uptime performance. Revenue per day stats exclude $2.2 million of early termination revenue recognized during the quarter, it also exclude pass-through costs of $2.7 million during the quarter.
Cost per day of $12,741 was also favorable compared to guidance and reflected cost-cutting initiatives implemented during the quarter. Cost per day statistics exclude $300,000 of decommissioning expense, unabsorbed rig overhead of $400,000 and pass-through costs of $2.7 million. Cost per day improvements reflect cost-cutting initiatives implemented during the quarter, but also benefited by approximately $470 per day from discrete items in the quarter associated with reduced property tax accruals and insurance matters.
SG&A expenses of $3.5 million, including noncash compensation expense of approximately $300,000 was sequentially lower, but came in about $300,000 higher than guidance. Sequential improvements reflect cost-cutting initiatives implemented during the quarter, which exceeded our original forecast.
However, our SG&A expense during the quarter was negatively affected by approximately $1 million associated with furlough costs associated with retaining employees in connection with obtaining our $10 million PPP loan. And our one-time costs associated with amendments to our credit facilities, merger consideration payment and related items.
With respect to the furlough costs, these represent forgivable costs associated with our PPP loan. But for accounting purposes, we won’t — we do not expect to recognize anything associated with loan forgiveness until that process is complete with the SBA, and that will likely occur in 2021. Depreciation, tax expense and interest expense came in consistent with our prior guidance.
During the quarter, cash payments for capital expenditures net of disposals were $2.6 million, $500,000 for expenditures during the quarter and $2.1 million associated with payment for first quarter deliveries that were not canceled as a result of the COVID-19 demand destruction.
Moving on to our balance sheet. At June 30, we reported net debt, excluding finance leases and net of deferred financing costs of $119.5 million, as net debt is comprised of our term loan and $10 million PPP loan. We repaid the $11 million outstanding at the end of the first quarter under our revolver and have no amounts outstanding at this time. Finance leases reflected on our balance sheet at quarter end increased as a result of an additional financing lease entered into during the quarter, reduced by ongoing finance lease payments and cancellation of vehicle fleet leases.
At June 30, we had total liquidity of $41.6 million, comprised of $17.4 million cash on hand, $15 million available under our term loan accordion and $9.2 million of availability under our revolver. Our backlog at June 30 stood at $14.9 million, 84% of which will expire in 2020.
Now moving on to third quarter guidance on operations as well as liquidity. With the caveat that forward visibility is almost nonexistent with respect to customer intentions, we expect operating days to approximate 360 days, representing 3.9 average rigs during the quarter.
As Anthony mentioned in his prepared remarks, we are at the execution phase of contract discussions for rig ads. But even if mobilization occurs during the third quarter, we do not expect a meaningful impact. There’s approximately 45 days and our guidance associated with those two rig adds.
We expect revenue per day to come in around $19,000 and $19,200 per day, and cost per day to come in around $15,000 and $15,500 per day. These per day amounts exclude pass-through revenue and expenses. Excluded from revenue per day guidance is $1.4 million of expected early termination revenue. Excluded from cost per day guidance is approximately $1.5 million we expect to incur during the quarter on yard decommissioning and stacking cost historically excluded from our cost per day stats. Also, pass-through costs are excluded from our cost per day guidance.
Sequential decreases in revenue per day reflect recontracting at spot day rates for our 1,000 horsepower rig at the end of the second quarter, which remains operating, but typically earns about $2,000 to $3,000 per day less than the rest of our 2,800, 1,500 horsepower super-spec rigs, and expected reactivation of rigs towards the end of the quarter at lower spot rate.
Sequential increases in cost per day reflect two things. As previously mentioned, the second quarter benefited from discrete items so that we do not expect to benefit ongoing quarters. That’s about $500 per day of the expected increase. And more significant is the 60% drop in operating days compared to the second quarter, which materially impacts fixed cost absorption for operating debt.
As Anthony mentioned, we expect the third quarter to be the trough for our operating rig count and expect this trend to move favorably when our operating rig count improves. We expect SG&A expense to approximate $3 million, including $0.5 million in noncash stock-based compensation expense. This includes approximately $300,000 of furlough costs. We expect to incur furlough cost through October of this year when the covered period for making qualified expenditures under our PPP loan expire. As mentioned, PPP loan forgiveness associated with these costs won’t be reflected in our financials until next year.
We expect interest expense to approximate $3.7 million, depreciation expense to approximate $11.2 million and tax expense to be approximately $100,000. For capital expenditures, we expect approximately $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 June 30, we had total liquidity of $41.6 million. As Anthony discussed, we took several actions that reduced near-term non-operating expenditures. Looking forward over the next 12 months, our required non-operating expenditures will consist of interest expense and finance lease payment and estimated required repayments under our PPP loan. We estimate these will aggregate to approximately $13.9 million, a significant reduction from our prior estimates as a result of actions we took during the second quarter. Again, on the PPP loan, with recent changes to the rules governing this program, we expect about half of that $10 million loan to be forgiven.
With respect to working capital and our revolver, although we will harvest a little more cash from working capital as our rig count troughs during the third quarter, our revolver availability is tied to our eligible accounts receivable balance. This is operations fall, availability falls.
In other words, we do not expect the revolver to be a source of liquidity going forward by non-operating expenses or cash flow shortfalls. However, as we reactivate rigs, it will be a source of liquidity to support required working capital investments. One final item. We expect weighted average shares outstanding to be approximately $5.2 million during the quarter.
And with that, I will turn the call back over to Anthony.
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. Go ahead.
Hey. Good morning, everybody.
Good morning, Kurt.
Hey, I appreciate the perspective here as we kind of work through the third quarter, and out to the fourth, and you guys indicated that you’re again seeing some demand for some additional rigs. It looks like you have two potential rigs that are expected to come back into the fold in the third quarter. As you look out into the fourth, how many additional rigs you think could potentially work their way back into the system?
Hey, Kurt, hope you’re doing well. Appreciate the question. Yes, we are anticipating starting up two rigs here back part of August rolling into September. Based on the discussions that we’ve underway with other clients, we would expect to put a couple more to work in addition to those two by the end of the year. Maybe there’s some upside beyond that. But just based on the quality of the discussions and the nature of the discussions we’ve underway right now, we’re pretty confident in 2 to 4 between now and the end of the year.
Okay. And then with respect to the pricing of the two rigs that are going to work here in the August, September time period, can you give us some sense as to what price points those are going to go out at?
Kurt, I would speak to that more generally. As I said in the remarks, there’s really not a spot market out there today. We have various inquiries that come in. It is hard to gauge the seriousness of those. When it comes to the actual price that gets submitted, it’s a pretty wide range of asks in terms of equipment, technology, that kind of stuff. I think the way that I would respond to that is anywhere from mid-teens to even low 20s, again, depending on what’s being specified in the way of equipment.
Obviously, we did secure the long-term 1-year contract extension on the rig over in the Haynesville, but that’s our 1,000 horsepower rig. So it would obviously be at the lower end of that range.
Got you. And then the last follow-up for me is, given the guidance and the perspective you guys have on the second half of the year, just wondering if you expect to be free cash flow and EBITDA positive during the second half?
Kurt, I think it’s going to be hard running average of 4 rigs this quarter and even putting rigs out next quarter. We are not going to — there’s going to be some reactivation costs. I think it’s going to be difficult for us to be EBITDA positive, certainly this quarter. And I think next quarter is going to be a challenge as well. So from a free cash flow perspective, I think it’s going to be difficult for us to generate any free cash flow in the back half of this year.
Okay. Appreciate that color. Thanks, guys.
Our next question is from Ryan Pfingst from B. Riley FBR. Go ahead.
Hi. Good morning, guys.
Ryan, how are you?
Good. Thank you, Philip. On the daily rig operating cost, it looks like it will be pretty volatile through the rest of the year. Can you guys give a sense of a run rate once things settle down a bit? Do you think you could get below $13,000 on a quarterly basis?
Well, yes, I do. If you think about it right now, or if you just look at the last quarter, we ran under $13,000 a day. Now there were some one-time items in there. So maybe it was normalized, it was low 13s. We are not going to be able to do that the back half of the year. Just we are not going to have enough rigs operating, and we’ve got a fixed cost we’ve got to absorb. But if we can get back to that 9 to 10 rig scenario, I think we can get close to 13. I don’t know if we will get below it. And if we get to 12 or so, I think we can run at below $13,000 a day.
That’s helpful. Thank you, Philip. And then one of your competitors noted last week that it sees performance-based contracts becoming the new norm over time. And that they’re leading with those types of contracts already today. Would you agree with that? And do you see that change happening in the market already?
I think, Ryan, if you look out longer term, I think the hope is that the industry does move more toward performance-based pricing. I think as I see the market today and certainly over the next couple of quarters, I think that’s going to be tough, just given how competitive the rig market is going to be. The focus today on lowering costs on the part of our customers. So, yes, we are optimistic that longer term, that will be the case. But I think in the short-term, that’s going to be a tough sale.
Thanks, Anthony. I will turn it back.
Our next question is from Daniel Burke from Johnson Rice. Go ahead.
Yes. Hey, good morning, guys.
Anthony, I thought you gave a pretty good synopsis of the marketing environment out there. And the way I heard it highlighted that the privates are possibly going to drive the initial stages of a nudge up in the land rig count. And I know it’s hard to generalize, but can you talk just a little bit longer maybe about the appetite you see from the publics to resume activity? And if not indications for late this year, how you think they will think about 2021?
Yes, it’s a great question, Daniel. That’s been a surprise for me over the last several years is in my experience throughout my career, the super majors, would tend to drill through the cycles, which was one of the reasons why you wanted to align yourself with them as a service provider. But today, I think just given the unprecedented nature of what everybody is dealing with — as you know, everybody has pulled in their horns, cut CapEx spend, paying very close attention to where they are spending their money. The discussions that I’m aware of that we are having with the bigger publics, it’s about living within cash flow, not just today, but as they think about next year and even beyond. Those are the reasons why I think their response and rebound in activity is probably going to be more muted than we would like to see. Remember also, many of them have huge inventories of ducts that they’ve built up. So as they think about that incremental CapEx dollar return on that spend, that’s likely where I would expect to see them spend that CapEx dollar. And it’s going to take a few quarters for them to work those inventories down. So I think there will be some things around the margin, as I indicated. But the publics, on the other hand, their challenge is really access to capital, as you know. So that’s the reason why we are a little bit more optimistic that we will see more of a rebound with the privates than we will with the publics over the next couple of quarters.
That’s helpful. I appreciate the comment there. Other one is a little more straightforward, and maybe for you, Philip. You kind of gave us the [indiscernible] perhaps to do this just a couple of minutes ago. But when you think about it, what’s sort of the range of contracted rigs you need to have to be in sort of an EBITDA breakeven or better position?
I think it’s more — obviously, it depends on day rate, but I think it’s hard for us to be EBITDA breakeven with less than 6 rigs operating through the quarter. And as we go back out, remember, we are going to — as rigs reactivate, the first couple are going to be pretty easy to get out. And they’re not going to cost money, not much money. But we are going to have some reactivation costs as well. So even when we go from 6 to 8, those quarters where we move — or 8 to 10, you are going to have some headwinds there on the EBITDA front that’s going to keep it depressed a little bit because we are going to have reactivation costs, just like the rest of our competitors. So on a normalized basis, 6, as we — if we go from 6 to 8, we are probably positive, but we will have some reactivation costs as well in there.
Got it. Okay. Great. I will leave it there, guys. Thank you for the time.
All right. Thank you.
This concludes our question-and-answer session. I would now like to turn the conference back over to Anthony Gallegos for closing remarks.
Okay. Thank you for that. Guys, we just want to thank everybody for making time today to dial in and participate in our second quarter earnings call here. With that, we will end the call. Thank you, everybody.
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.