Helmerich & Payne, Inc. Q3 FY2021 Earnings Call

Good day, everyone, and welcome to today's Helmerich & Payne's Fiscal Third Quarter Earnings Call. At this time, all participants are in a listen-only mode. Later, you will have an opportunity to ask questions during the question-and-answer session. Please note today's call may be recorded. I will be standing by should you need any assistance. It is now my pleasure to turn the call over to the VP of Investor Relations, Dave Wilson. Please go ahead.

Thank you, Reed, and welcome, everyone, to Helmerich & Payne's conference call and webcast for the third quarter of fiscal year 2021. With us today are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. John and Mark will be sharing some comments with us, after which we'll open the call for questions. Before we begin our prepared remarks, I'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based on current information and management's expectations as of this date and are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties, and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q, and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements.

And team, we are experiencing technical difficulties. You will hear music until the program resumes.

Thank you, Reed, and welcome, everyone, again, to Helmerich & Payne conference call and webcast for the third quarter of fiscal year 2021. With us today are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us, after which we'll open the call for questions. Before we begin our prepared remarks, I'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based upon current information and management's expectations as of this date. They are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties, and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q, and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You'll find the GAAP reconciliation comments and calculations in yesterday's press release. With that said, I'll turn the call over to John Lindsay.

Thank you, Dave, and good morning, everyone. Since the industry rig count hit bottom almost a year ago, H&P's rig count and market share gains have positioned us as the leading drilling outcomes provider in the US land market. In line with our guidance, we exited the third fiscal quarter at 121 rigs. And today, we are at 123 active FlexRigs. We expect to continue to have a moderate and somewhat choppy upward trajectory in our rig count, as well as improved pricing over the next quarter. Although there are approximately 260 idle super-spec rigs available in the US market, we believe fewer than 10 of those rigs have actually worked within the past 12 months, and many of those rigs have been idle for well over 18 months. There's a high cost involved in reactivating long-idled rigs, which typically presents one of those classic 'pay me now or pay me later' conundrums. Most importantly, striking the right balance to startup enhances the safety of an operation, but it can also significantly impact the value proposition for customers by driving better metrics and drilling performance, downtime, and crew retention. Our stellar track record of efficient startups delivers greater customer adoption and is one reason why we consistently outperform as the rig count increases. As demand grows, these reactivation expenses will continue to drive rig pricing higher as the supply of work-ready super-spec rigs becomes scarce. All the drivers that lead to enhanced pricing and contract economics are in place: higher crude prices, higher activity levels, higher reactivation costs, pricing discipline within the industry, and perhaps better outcomes for our customers. In light of these factors, we have been in discussions with customers to increase pricing. Further, we remain optimistic that current oil prices will translate into higher 2022 E&P drilling budgets and activity in the US land market. As of today, discussions with customers regarding activity for the rest of 2021 inform our estimate of approximately 50 to 75 incremental industry rigs returning to work by year-end, and we expect that to be back-end loaded in the fourth calendar quarter. That expected rig increase, coupled with the long idle fleet, also enhances the potential for further rig pricing improvements in the fourth calendar quarter and into 2022. Assuming oil prices remain stable and near current levels, we would not be surprised to see 2022 budgets for public companies drive further incremental increases in rig activity next year. We expect the Permian will continue to lead the way in incremental rig adds. Our leadership position in this region is multifaceted. We have a superior infrastructure, experienced people, the leading number of active super-spec rigs at 67 rigs, as well as the largest inventory of idle super-spec rigs. This combination of attributes bolsters the company's capacity for further growth in the Permian Basin. With this context in mind, let's now turn to field performance and the implementation of digital technology solutions combined with new commercial models. There is a growing appreciation for the value proposition H&P provides, as we're successfully growing our rig count with existing customers as well as partnering with new customers to achieve better drilling outcomes. When utilized on a FlexRig platform, H&P's digital technology and automation solutions like AutoSlide are enhancing drilling outcomes both in terms of efficiency gains and wellbore quality, resulting in improved long-term well economics and returns. We have multiple customers, large and small, public and private, utilizing our FlexRigs and digital and automation technologies. This combination enables them to reliably lower their overall well costs, improve wellbore quality, and reduce downhole risks. Let me give an example recently where we had a customer with a performance contract that was paying us well over market spot rates. They were nervous about explaining that to their management team. However, they also mentioned to their management team that they were saving over $0.25 million per well by using H&P. So as a result of that realization, management wanted to continue to use H&P on all their wells, and that expanded our rig count with that customer. This outcome-based approach, which is data-driven, delivers more predictive, consistent, and superior well results over an entire drilling program for our customers. The great news is these aren't one-off examples. We have these partnerships and results with major large E&Ps and private companies. Over the past few decades, the methods, the equipment, the technology, and the risk profile in the drilling of unconventional oil and gas wells has evolved significantly. However, the legacy dayrate model construct has not. The pricing model for providing better drilling outcomes will continue to evolve, and H&P, along with several of our customer partnerships, is pioneering new commercial models to better align our performance with our customers' goals and allow us to share in the value-added outcomes we help create. Unless a pricing model can equitably share the benefits derived through better technologies and efficiencies, the ability of the industry to continue to innovate and improve will diminish. We're pleased to see international activity start to pick up again after a long pandemic-driven hiatus. We are participating in several tenders with both NOCs and IOCs, but these are very thoughtful, slow processes and uncertain of timing. In addition to working on new growth opportunities, Argentina and Colombia appear to be ready to put rigs back to work during our fourth quarter. We are seeing some traction of our digital technology and automation solutions internationally as well. Our international FlexRig digital platform is capable of hosting our automation solutions, which we believe will be a driver of additional FlexRig adoption. Before turning the call over to Mark, I wanted to touch on sustainability. We have a long history of offering solutions, which helped both H&P and our customers' sustainability needs, and we continue to invest in these and other sustainability efforts that benefit all our stakeholders, our employees, our customers, vendors, investors, and society at large. We're partnering with our customers and taking a thoughtful and methodical approach to offer solutions to fit their desired outcomes, both from an environmental and economic perspective. We have many solutions in our toolkit that we've had for many years, such as using alternative power sources at the rig like natural gas engines, high line power, or dual fuel engines. But more recently, we've invested in energy storage solutions using battery technology and rig engine efficiency software solutions to help reduce greenhouse gas emissions and lower rig fuel consumption. As I mentioned on the last earnings call, we are committed to publishing our inaugural sustainability report in 2021, which will include important data and information about our sustainability efforts and successes. In parallel to the development of the report, we have also increased sustainability disclosures on our website, which includes data and information about emissions, safety, and diversity, equity, and inclusion. Last year, one of the renewable investments we made was in geothermal resources. Many years ago, we intermittently drilled conventional geothermal wells, but a new unconventional closed-loop approach to geothermal is creating a viable source for renewable energy going forward. H&P has a team dedicated to investing and participating in geothermal, where our drilling technologies and expertise are readily transferable. So in closing, we remain optimistic about the industry and our ability to capitalize on our scale and our distinct capabilities as we focus on delivering the best outcomes for customers and value for our shareholders. And now I'll turn the call over to Mark.

Thanks, John. Today, I will review our fiscal third quarter 2021 operating results, provide guidance for the fourth quarter, update remaining full fiscal year 2021 guidance as appropriate and comment on our financial position. Let me start with highlights for the recently completed third quarter ended June 30, 2021. The company generated quarterly revenues of $332 million versus $296 million in the previous quarter. The quarterly increase in revenue was due to higher rig count activity in North America Solutions as expected. Total direct operating costs incurred were $257 million for the third quarter versus $232 million for the previous quarter. This sequential increase is attributable to the aforementioned additional rig count in the North America Solutions segment. General and administrative expenses totaled $42 million for the third quarter, also consistent with our expectations. Our Q3 effective income tax rate was approximately 30%, which was above our previous annual guided range. Taxes were positively impacted by a discrete tax benefit primarily related to a change in the state deferred income tax rate. To summarize this quarter's results, H&P incurred a loss of $0.52 per diluted share versus a loss of $1.13 in the previous quarter. Third quarter earnings per share were impacted by a net $0.05 gain per share of select items as highlighted in our press release. Absent these select items, adjusted diluted loss per share was $0.57 in the third fiscal quarter versus an adjusted $0.60 loss during the second fiscal quarter. Capital expenditures for the third quarter of fiscal 2021 were $18 million, with year-to-date spending levels below our previous implied guidance. Planned spending continues to shift to the right, but we are expecting a more significant spend in our fourth fiscal quarter, which we will discuss later. Turning to our three segments, beginning with the North America Solutions segment. We averaged 119 contracted rigs during the third quarter, up from an average of 105 rigs in fiscal Q2. As John mentioned, we exited the third fiscal quarter with 121 contracted rigs. We also had approximately 15 rigs roll off term contracts and into shorter-term contracts during the quarter as customers maintained their budgeted drilling programs. Revenues were sequentially higher by $31 million due to the aforementioned activity increase. North America Solutions operating expenses increased $20 million sequentially in the third quarter, primarily due to the addition of 12 rigs. The one-time reactivation expenses associated with those rigs was approximately $6 million in fiscal Q3. Looking ahead to the fourth quarter of fiscal 2021 for North America Solutions. As expected, rig count growth was more moderate during the third quarter. As of today's call, we have 123 contracted rigs, and our expectation is to end the fourth quarter of fiscal 2021 with between 127 and 132 contracted rigs. Publicly traded customers continue to operate within their calendar year budget plans. So most of our recent active rig additions were driven by privately held customers. We still see opportunities for publicly traded customers to add rigs late in this calendar year as capital budgets are refreshed heading into 2022. In the North America Solutions segment, we expect gross margins to range between $72 million to $82 million with no early termination revenue expected. As we continue to add rigs, one-time reactivation expenses continue to pressure margins. We expect those expenses to be approximately $8 million in the fourth quarter. As I mentioned in the last quarter, the length of time a rig has been idle and the costs required to reactivate it have a direct correlation. Most of the rigs we are reactivating in the fourth quarter have been idle for 12-plus months. Reactivation costs are mostly incurred in the quarter of start-up, so the absence of such costs in future quarters is margin accretive. That said, some expected reactivation costs in the quarter ended September 30 will be for rigs readied for October commitments. As John mentioned, we are expecting to achieve higher pricing in light of higher demand and tight ready-to-work super-spec supply. However, due to varying effective dates of new rates, most of the benefits on margins will be realized in fiscal 2022. Our current revenue backlog from our North America Solutions fleet is roughly $493 million for rigs under term contract. Regarding our International Solutions segment, International Solutions business activity averaged approximately 5 active rigs quarter-on-quarter, and we did add a sixth rig late in the third fiscal quarter. Margin contribution was in line with expectations for the quarter, albeit towards the low end of the range. As we look toward the fourth quarter of fiscal 2021 for International, currently, our activity in Bahrain is holding steady with three rigs working, and we have three rigs under contract in Argentina. During the quarter, we expect a little churn in our international rigs as a rig in Bahrain is expected to stack, but an additional rig in Argentina is expected to commence work. Further, the contracted rig in Colombia is expected to commence operations very late in the quarter. In the fourth quarter, we expect operating gross margins to be between breakeven and a loss of $2 million, apart from any foreign exchange impacts. Turning to our Offshore Gulf of Mexico segment. We continue to have 4 of our 7 offshore platform rigs contracted. Offshore generated a gross margin of $9 million during the quarter, which is at the high end of our guided range. As we look toward the fourth quarter of fiscal 2021 for the offshore segment, we expect that offshore will generate between $7 million and $9 million of operating gross margin. To conclude third quarter results commentary, I will highlight our non-operating and other segment activity. As a reminder, at the start of fiscal 2020, we elected to set up a wholly owned insurance captive to ensure the deductibles for our workers' compensation, general liability, and automobile liability insurance programs from October 1, 2019, forward. Our operating segments pay monthly premiums to the captive for the estimated losses based on an annual external actuarial analysis. The result is a transfer of risk from our operating subsidiaries to the captive for the deductibles, which are our self-insurance retention. The actuarial estimated underwriting expense can vary from quarter to quarter as claims develop, get settled, or dismissed. For the three months ended June 30, 2021, the estimated reserves in the captive were adjusted upward for self-insurance claim developments. Now let me look forward to the fourth fiscal quarter and update fiscal full year 2021 guidance as appropriate. Capital expenditures for the full fiscal year 2021 are now expected to be at the low end of the previously guided range of $85 million to $105 million, with, as mentioned earlier, more spend expected during the fourth fiscal quarter than the preceding three-quarter average. This back-end weighted fiscal year spend is primarily due to some skidding to walking pad capability conversions as a result of select customer demand. Our expectations for general and administrative expenses for the full fiscal year 2021 have not changed and remain at approximately $160 million. We also remain comfortable with the 19% to 24% range for estimated annual effective tax rate and do not anticipate incurring any significant cash tax in fiscal year 2021. The difference in effective rate versus statutory rate is related to permanent book-to-tax differences as well as state and foreign income taxes. Now looking at our financial position. We had cash and short-term investments of approximately $558 million at June 30, 2021 versus $562 million in March 31, including availability under our revolving credit facility, liquidity was approximately $1.3 billion. Our debt-to-capital at quarter end was about 14%, and our net cash position again exceeds our outstanding bond. As a reminder, we have no debt maturing until 2025, and our credit rating remains investment grade. Given our current outlook for activity, we expect to see minimal changes in our cash balances at fiscal year-end compared to June 30 balances. At today's activity levels, we believe our early operating earnings will fund our maintenance capital expenditures, debt service costs, and dividends. Our expectations beyond next quarter for rising activity drives our run rate cash generation higher, while on the other hand, at least in the short term, a good portion of that higher cash generation will be consumed by reactivation expenses and working capital investments required to enable that future higher activity. As John mentioned, cost control remains a high priority. Since we last spoke on the March earnings call, we are advancing along several workstreams that are being carried out in parallel to adjust our cost structure. Some items expected to be completed in the fourth fiscal quarter will culminate in approximately $7 million in annualized savings primarily in operating expenses. We are working on other initiatives that will be completed in the coming quarters to further optimize future run-rate expenses. As these plans progress, we will provide updates on future calls about the expected magnitude and timing of these various cost structure initiatives. That concludes our prepared comments for the third quarter. Now let me turn the call over to Reid for questions.

We will take our first question from Tommy Moll. Please go ahead.

Good morning and thanks for taking my questions.

Good morning, Tommy.

John, I wanted to start on the issue of cost inflation. Any anecdotes or numbers you could offer in terms of what you're seeing, whether it be on the labor side, transport materials, anything that's hitting that average daily cost line you'd want to call out?

Well, Tommy, our labor costs have not increased. We didn't reduce our wages in the field operations during the downturn, so there hasn't been any impact there. There's not really anything specific we can point to other than the costs associated with reactivating rigs. Overall, you've heard discussions in the industry regarding tubulars, both casing and drill pipe. Drill pipe is likely something we will need to acquire more of in the near future, and I would expect that with steel prices up, the cost of tubulars is going to be higher. Those are the main aspects related to inflation that come to mind right now.

That's helpful. I wanted to follow up on the geothermal comments that you made. In the earnings release, you talked about some investment opportunities into other companies. So I just wondered if you could share any thoughts around what those might look like, or should we think about these as likely modest size investments or something larger? And more broadly, just anything else you want to offer in terms of the opportunity you're going after there with geothermal generally would be great.

Sure. Well, like we said in our remarks, we think it's a great opportunity that there's several different technologies that are out there that are much different than seen forever. I mean, I remember hearing about wells we drilled probably back in the '60s and the '70s, but much different type of operation. I think these are opportunities for us, yes, to make investments in the companies which we have, but they've been modest investments. But it gets us a seat at the table, and there are some partnership opportunities. There's definitely transferable expertise that we have as a driller and as a technology provider that we can use. So we've made some really strong, what I would consider early partnerships with three different companies, and I think we're going to actually have 1 operation that will be starting up here soon, a drilling operation if I'm not mistaken. So that's encouraging. Mark, do you have anything?

No, John, just that as it relates to the drilling operation, we have some of these investments into these early partnerships that are in cash and some are in the form of any kind of investments through the drilling services. In addition to the three John mentioned, we have a couple of other things in the pipeline, including an LOI on line. So excited about a variety of different technologies in the geo spectrum, including the closed-loop system John mentioned in the prepared remarks as well as some other burgeoning technologies as well.

Thank you. I will turn it back.

Alright, Tommy. Thanks.

We'll go next to John Daniel with Daniel Energy Partners. Please go ahead.

Hey, good morning, guys. Thank you for putting in the call.

Hi John.

Hey, I'm driving here so, I might have missed something. But if I heard you correctly, opportunity for, call it, 50 to 75 rigs across the US by year-end.

Yes.

And mental math does here about 25% of the US market ballpark, give or take, and you have an excellent reputation. So my question is, what if you just said no to your customers if they don't want to sign your pricing model? What happens?

Well, I would imagine there would be. Well, first of all, that you know if that wouldn't be our approach.

No, I know that, hypothetical.

We view this as a partnership. The market is competitive, and customers are seeking optimal solutions that provide better and more reliable outcomes. Our history of successfully starting rigs from a dormant state is strong; only a few rigs have operated in the past year, with the majority remaining idle for 15 to 18 months. It's essential to work with a partner who can effectively deliver results right away. While this is a complex question, the positive aspect is that some customers are interested in changing their model as they recognize the improved results it can offer. Although certain customers may prefer to stick with the day rate model, we will continue to push for better pricing in that area as well.

Do you find that those who are willing to embrace that model are more likely to be larger public companies, or is that not the case?

John, in the past, we didn’t have nearly as many rigs working for private companies. However, I am very encouraged that across the board—whether it’s super majors, large independents, mid-cap companies, or small private firms—our customers are interested in technology. They want to improve their effectiveness, efficiency, and reliability. We are all aiming to make our businesses operate as efficiently and effectively as possible, and we are collaborating with other suppliers to achieve that. I believe this trend will continue. A great example is the increasing number of private companies utilizing AC drive, super-spec rigs today, compared to three years ago when many were using smaller players with SCR rigs and even some mechanical rigs. There has been a significant shift. The most sophisticated private companies, those excelling in their sectors, are the ones attracting investment dollars, and we are pleased to partner with them.

Okay. Well, very good color and good anecdotes in the messaging on the prepared remarks. The final one for me, more, I guess, housekeeping, I guess. But can you remind me where you peaked in Argentina? And then, just some thoughts on that specific market as you head into next year.

When I say 10 or 11, was it 10 to 11, Dave, you remember the count what you had at the map.

11, yes.

So we have three working now and the fourth one, as we said, about to go back to work, with discussions with operators for even more interest.

Okay. Thank you, guys, very, very much.

Thanks, John. Be careful.

We'll go next to Vebs Vaishnav with Coker & Palmer. Please go ahead.

Thank you for taking my question. It seems that short-term improvements could come from reactivating rigs that have been idle for an extended period. Could you provide some insight into the current costs associated with rig reactivation, where those costs might head, and how the payment structure works for that? Additionally, could you help us understand the factors that influence day rate increases, especially considering there are still around 200 super-spec rigs available? That would be really helpful.

We'll start with the reactivation process and then turn it over to Mark. Cost-wise, reactivating a rig in our fleet today ranges from $400,000 to $500,000. Initially, when considering how many rigs we've reactivated, we've done about 76 or 77. The earlier rigs cost around $100,000 to $150,000 to reactivate. As we tackle rigs that have been idle longer, the costs increase. Our goal is to recoup these reactivation costs, which can be achieved in several ways, including performance-based pricing or a portion of the term. We won’t reactivate a rig unless we have sufficient work lined up to justify the investment. We also aim to share the improved outcomes we provide, and fortunately, we have customers willing to do that. Is there anything else to add on this question?

I'll just footnote that with some numbers detail, John. And if you think about the margins from our perspective, the regular apples-to-apples, quarter-to-quarter operating margins bottomed out in Q4 of fiscal 2020. And what we've seen this year and margins are affected by these recommissioning costs primarily. If you think about what we just guided for Q4 that we're in now, $8 million. If you do the math on that, that can basically equate to about $700 a day detriment to our Q4 earnings. So in the absence of that, Q1 fiscal 2022, $700 improvement in margins just for those reactivated rigs. Is that helpful?

That's a fair point. It actually leads nicely to my next question. You've clearly made progress in reducing costs, and I understand you are still focused on that. Looking ahead a couple of years, if we consider a scenario where around 200 H&P rigs are operational, how should we view the normalized cost when we exclude the rig reactivation expenses and establish more stable base cost levels? Can we...?

Sorry, go ahead.

I was just trying to say if it would come back to 13,000, 14,000 level, or is that a different level now?

It's TBD. There are pressures in multiple directions, but just to remind you a little bit, last year, we had significant across-the-board cost reductions. I think we took in the last fiscal year, about $50 million out of OpEx, $25 million out of SG&A. And that was to reduce what had been a growth scale for the company. So we did not cut to the bone, and we have the largest super-spec capacity. We have the highest public company exposure, which positions us well for potential calendar year 2022 budgets and the resulting rig additions. So what we're working on now, Vaib, is really further cost-out initiatives that are very targeted. We're trying to improve efficiencies internally in processes, service delivery models, automation, and technology. So that $7 million we just mentioned is the first installment as we continue to work through numerous work streams internally. So it's too early to tell. But suffice it to say, we are working to get that historical daily average cost back down and then just see how the market moves in the interim, not really related to any inflation questions. As John said, we certainly aren't experiencing that in labor today, but we just have to see as we unfold through the coming quarters what happens if we put pressures in the other direction.

And maybe if I can squeeze in last one. So, obviously, you guys lowered the CapEx budget towards the lower end for this fiscal year. Given the steel prices increasing and activity increasing, how should we think about CapEx for next year?

Well, we've been at this lower CapEx level, as you said. And in the short term, we hope to continue a bit of momentum in that range. But I think it's early days. We're actually in our budgeting process as we speak. So not ready to be definitive yet, but through fiscal 2022, I could see we're south of $500,000 per active rig maintenance CapEx per annum today. I could see us going from a $500 million to $750 million range in fiscal 2022, although as I said, early days in our budgeting process. And then as we move through time, maybe to fiscal 2023 prognosticating back to the historical range of $750,000 to $1 million. So we're still benefiting from being able to harvest a lot of the componentry that we had back when we were scaled up to be a larger growth company. And as we move through time and reactivate rigs, we'll obviously have to eventually catch it back up harvesting those components that really benefited us here in fiscal 2021.

That’s helpful color. Thank you and thank you for taking my questions.

Thank you.

We will go next to Waqar Syed with ATB Markets. Please proceed.

Thank you for taking my questions. John, as your rigs return back to work in the international markets, do you expect the day rates to be higher than what they were getting before they were stacked, or do you think they're going to be discounts versus prior day rates?

Well, we have some rigs that have gone back. I'm not certain on what our level of pricing is today versus when idle. I don't know, Dave, if you do?

It's going to vary.

Yes. I think it's some cases, they'll probably be similar. And again, I wish I knew more of the details, Waqar, but I don't at this stage. I would imagine early on, there'll be probably some discount compared to when there were more rigs running just from a supply/demand perspective.

Okay. So the market right now for International generally, you would say is still – despite reactivations – cost to reactivations, rates are likely to be softer for now until maybe a year from now when the market tightens a little bit. Is that a fair statement?

It's really difficult to predict beyond a quarter or two. However, it doesn't take much activity to increase the rig count and rig supply quickly in countries like Argentina, which could lead to improved pricing. The international market has been slow to respond. We do expect things to pick up soon, but it's challenging to make specific predictions about pricing at this time.

John, I'll just add to that. I think in certain markets, it could be analogous to what we've been talking about today with the US. And for example, some of these customers in Argentina are interested in super spec. So again, you get to that very tight supply meeting that customer demand, and that is as we are experiencing in the US now, and it's very helpful to pricing.

Now in Bahrain, you mentioned that your rig is stacked. In general, our view would have been that more rigs are going to go back to work. So this is kind of a surprising data point that a rig is being stacked that was working. Is there anything in specific to that particular rig or that particular client, or how should we be reading that data point?

It's just where the customer is at this point in the program?

Yes. I think it's budget-driven. It's one of those things that we're so good. We drilled ourselves a little bit out of work. And so, I think we had 3 rigs running and they just have enough budget to run too for the next whatever period of time. My assumption would be the third rig would eventually go back to work. But generally speaking, there's not been a huge change in the program.

Okay. Just last question. We hear about labor shortages and especially on the trucking side and with truck drivers. Are you seeing any inefficiencies develop in the whole drilling process because the sites are not getting ready on time or getting equipment on time at the well site and thus well time to drill wells is increasing or you're not seeing that at the moment?

Waqar, at least in our operations, I can't really speak to others. We've got very high levels of performance, efficiency levels are high. Our customers are managing their pad construction well. I mean, you're right, there is really an overall national shortage on truck drivers. To my knowledge, we've not had a huge impact in moving our rigs. The good news is, we don't move rigs as often as we used to because of pad drilling. But in general, I see us performing at very, very high levels. Really, we've not had any challenges to speak of related to people. We've got a great group of people in the field, great leadership and a pretty strong bench. So, we're pleased with that. But I can't think of anything where we're having to wait and we're seeing inefficiencies.

Great. Thank you very much. Appreciate the answers.

Thank you Waqar.

We will go next to Neil Mehta with Goldman Sachs.

This is Artie on for Neil. So, looking at the rest of the year and into 2022, most of the incremental activity here on seems like it could be driven by the major – potentially some private as well. Could you remind us of the exposure you have with them relative to your peers and what the upside could look like for you in terms of the number of rigs that could be added from here on?

Sure. That's a great question. I will say that, it's interesting and we've all heard these numbers. But one snapshot is the last 100 days, 42 rigs have gone to work, and 39 of those rigs were from privates. So, privates have really been making a difference in '21, about 75% of the work. We got 11 of those 42 rigs. But I think going forward, it's going to be a combination of the majors, large independents, I think just the publicly traded companies in general, when budgets are reset for 2022. Let's assume the current budgets are $45 to $50. If you think about a $60 million, $65 million type number is going to have, I think, a pretty significant pickup in activity. So I think it could be that we're seeing some of that even hitting at the back half of the year. I think our current exposure, I think we've got 35% of our current fleet working for privates. Historically, it's been 20%. So we're very pleased with that ability, but we still have 65% of our current fleet with the public. And if you look at those customers who were our largest customers, prior to the pandemic, those were the companies that reduced their rig counts the most. And so again, our hope is that those companies are responding in a strong fashion for a much stronger 2022, and we'll see an outsized growth on our rig count. That's our hope.

It appears that about 80% of the currently active rigs are super spec based on the supply numbers you've shared. What would you consider the maximum share of super-spec rigs in the active US rig count?

It continues to grow share. Currently, there are 70 legacy SCR rigs still in operation. We're observing a mix of small and large exploration and production companies that are expanding their super-spec capacity. This makes sense because laterals are getting longer, and well complexity is increasing, making these rigs more efficient for drilling. Coming off older technology like SCR mechanical rigs, the data from our FlexRig platform allows us to leverage technology and software solutions that older rigs can't provide. At some point, we expect the number of these rigs to decline further as their value proposition is significant.

Great. That's very helpful. Thank you. I’ll turn it back.

Okay, thank you.

Hey, good morning. It seems that margins are beginning to improve for the reasons you mentioned earlier. Mark, you briefly addressed this, but do you think that the fourth quarter of fiscal 2022 marks the lowest point for North America Solutions margins? And do you anticipate margin growth as we move into the first quarter of fiscal 2022?

Yes. Well, I said in Q4 2020. So certainly, we're going to continue to have, as I've mentioned, drag on current earnings with the recommissioning expenses. But as those free up eventually and you have a more normalized higher rig count, certainly more cash flow and margin from the absence of those costs. But maybe more importantly, all the stuff John has been talking about this morning related to pricing that can help drive up those margins. So I think those two things added together bode quite well potentially for fiscal 2022.

Got it. So just to clarify, do you believe your margins will come up from this 6,600 implied range even with the burden of the reactivation costs, just thinking about the trajectory as we start in fiscal 2022?

Well, that's going to depend. We just have to see how many reactivations we have in those quarters that we have not yet guided to.

Okay, understood. I wanted to expand on the geothermal market. I wanted to get your thoughts on what you see as a total addressable market for you guys? And maybe any insight of what that could mean in your top-line growth over the next three to five years as this starts unfold?

I believe we have done some modeling, but it's still too early to provide a specific number since these technologies are still under development. The technology seems promising, but we need to actively pursue it and determine how much energy can be generated over time. I think it has the potential to make a significant impact. Our internal capabilities and expertise align well with this opportunity, but estimating a figure at this point is quite challenging.

And just a footnote, some details why that's so hard. In our own research and modeling, certainly what we're trying to do is have an alternative use for the installed rig base of assets, and we do see opportunity for that. But as John is saying, what that is, it's hard to pinpoint if you even go to US Department of Energy, potential wells that could be drilled; it just varies wildly. And why is that? That's because all of these technologies are in such early stage development. It's hard to know which of them will be successful and if successful, to what scale they'll be applied. So more to come, but great days.

Yeah. And again, I think one of the things that's exciting for us is the transferability of these technologies that we're using to drill these horizontal wells. We drilled a U-shape horizontal well a couple of weeks ago that was just amazing when you look at it. And you just think about that type of technology and how we're just continuing to advance in our capabilities. But as Mark said, it's just impossible to nail a number at this stage.

Right. No, fair enough. All that color was very helpful. And then if I could just squeeze in one more. You talked about some of the newer equipment on the rig side, emissions friendly, also helps economically. Can you just maybe give us some details around the emission savings when thinking about high line or dual fuel or some of this power management with battery backup? I'm just curious your thoughts on how emissions this is saving, how much of a needle mover this is for your customers as far as being used more friendly with ESG.

High Line Power has been in operation for a long time. In fact, the first FlexRig we constructed was on High Line Power. The challenge lies with the local grid. Additionally, the source of power generation plays a role; for example, whether it involves burning natural gas or coal. Natural gas is a very clean fuel. Over the past two to three years, our company has achieved a significant percentage reduction in emissions.

We're around 10%.

We've achieved around 10% to 11% in emissions reduction, largely through more manual methods. As we enhance our power management at the rig site, even with diesel usage, we expect to further improve our emissions. I don't have specific figures for dual fuel at the moment.

It's really going to depend on the location and application.

Yes, there are challenges at times related to dual fuel applications due to methane slip. However, we are continuing to drive improvements, which you will see in our sustainability report to be published later this year. Currently, battery power has some advantages, though it is not very economical because of battery costs. We are also exploring other solutions internally to assist our customers in reducing emissions. At this point, I don't have specific numbers, but more information will be available in October or November.

Great. And I'll look forward to it. That’s all my question. Thank you.

Okay. Thank you.

Time for one last question, Dave, as we started a little late.

Yes.

And we'll take our last question from Arun Jayaram. Please go ahead.

Hey good morning. Arun Jayaram with JPMorgan. John, you mentioned

Good morning.

Good morning. You mentioned for the calendar year you expect, maybe 50 to 75 incremental rigs industry-wide with some potential for maybe a mix shift over time towards the publics. I was wondering if you can maybe comment on at a basin level where you're using some of the incremental rig demand and are you starting to see some improvement in demand conditions in natural gas basins with natural gas now, at least the stock prices, near-term prices at $4 per MCF?

We were actually discussing this earlier today. It has been about 30 days since we observed a significant increase in natural gas prices, and we're starting to see that reflected in the market. Hopefully, customers will begin investing more in drilling for natural gas. I find that encouraging. There's interest in several natural gas regions, including some of the gassier areas in the Eagle Ford. Overall, there's interest across the board, whether in the Northeast or other gassy basins.

Yes. And then you mentioned in terms of majors, you would expect, call it, their activity has been actually down since the bottom of the rig count. So you'd expect the new budgets and next time that could rekindle some of that demand for the majors, is that correct.

That's what we're expecting and what we're seeing in discussions with customers. It really only makes sense. All of the exploration and production companies have done an excellent job of being disciplined and adhering to their budgets. In a higher commodity price environment, regardless of whether the oil price is $60, $65, or $70, we will see significantly larger budgets than we have today. Therefore, I do expect to see rig counts increase among the major companies, as well as all of the publicly traded firms we have spoken with, who have mentioned needing rigs in late Q4 or early in the first calendar quarter of 2022.

Great. And then, just my follow-up. John, the entire industry has historically been driven by a day work kind of philosophy. You've explained the evolution of your contracting approach. I wanted to ask you what barriers you see from traditional exploration and production major procurement departments that have focused on day work. Is it challenging to overcome some of these historical barriers as you progress?

I would characterize it as change. Change is never easy, and this industry isn't easy to transform. We all face challenges with it. However, we are also tasked within our companies to find better, more efficient ways to operate. You can't achieve prosperity just by cutting costs; investments in technology are essential. Supply chain factors into this, but the customers we partner with, both large and small, recognize the value of it. For instance, if we can collaborate, implement our technologies, and share in savings—saving the customer $0.25 million, for example—that's what they truly want. It's about effectively using technology and developing commercial models that benefit both sides. We aim to share in those savings because we are investing real money in our technology solutions, having allocated millions toward them. Ultimately, these solutions provide significant value to customers. It can be slow at times; the early days of the FlexRig were challenging. Nevertheless, we have early adopters, which is encouraging. This business is relatively small, so people exchange ideas and start to experiment with new concepts. We find that promising.

Great. Thanks a lot, John.

Alright. Thank you. Have a good day.

And there are no further questions. I'll turn it back to the speakers for closing remarks.

Okay. Thanks again, everybody. Sorry for a little bit of a late start there. But again, we remain optimistic about the industry and how things are looking for the rest of 2021 and going into 2022. So look forward to talking with you in November. Take care.

And this does conclude today's program. We appreciate your participation and you may now disconnect.