Helmerich & Payne, Inc. Q3 FY2022 Earnings Call

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

Thank you, Ashley, and welcome everyone to Helmerich & Payne Conference Call Webcast for the Third Quarter of Fiscal Year 2022. With us today are John Lindsey, President and CEO; and Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us afterwards, we'll open the call for questions. Before we begin our prepared remarks today, 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, and they're not guaranteed future performance. Reporting statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, or quarterly reports on Form 10-Q and 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 make reference to certain non-GAAP financial measures such as segment direct margin and other operating statistics. You'll find the GAAP reconciliation, comments and calculations in yesterday's press release. With that said, I'll now turn the call over to John Lindsey.

Thank you, Dave. Good morning, everyone. And thank you for joining our call today. I'm pleased with our performance during the quarter. The operational and financial results continue to reflect the benefits of our strategic initiatives we've been working on for several years now. In particular, the efforts by our sales and operations teams to improve pricing and margin growth in our North America solutions segment. On our earnings call last February and again in April, we discussed how rig pricing needed to reach $30,000 per day. In our third fiscal quarter, we had roughly 20% of our fleet average revenue per day at or above that level. This is a great start. But we also recognize that pricing needs to move further to achieve gross margins of 50% or greater to generate returns that fully reflect the value we deliver to customers with our flex fleet rigs and complementary technology solutions. As intended, we saw a modest growth in rig count and exited the quarter with 175 rigs contracted in our North American solution segment. Fiscal discipline and contractual churn allowed us to re-contract rigs without incurring additional reactivation costs and to redeploy them at significantly higher rates. Our rapidly improving contract economics are driven by both H&P’s value proposition to customers as well as a market that's very tight for available super spec rigs. We believe the drilling solutions and outcomes we provide are increasingly being recognized and coveted by customers. It's encouraging to see capital discipline in our industry. And when combined with the supply chain and labor constraints, we expect this could dampen the industry's ability to reactivate idled super spec rigs at significant scale during the buying season, which has historically occurred in calendar Q4 and Q1. This will likely perpetuate the supply-demand tightness for super spec rigs and provide momentum for future improvements in contract economics. We are already seeing some customers inquiring about rig availability for the fourth calendar quarter of this year. They are realizing that the market for readily available H&P flex rigs is extremely tight. We're seeing customers looking to add incremental rigs for 2023, typically in the range of one to four rigs, and some looking to replace lower performing regular rigs with flex rigs. However, we are unable to comment on the specific number of rigs that we can add today. It is important to underscore that going forward, we will apply the same disciplined focus on financial returns and ensure we are receiving commensurate compensation for the value we provide. Along those lines, Mark will provide some high-level remarks on our fiscal 2023 CapEx response to potential future demand for our rigs and idle super spec rigs. We continue to hear about the benefits our customers experience from our digital technology solutions, especially when combined with our uniform flex rigs fleet. As horizontal wells trend toward greater complexity and longer lateral length, drilling efficiency and reliability are critical factors that differentiate our premium super spec service offering. On the international front, activity is increasing with further improvements in our South American operations and potential for more activity in the coming quarters. In the Middle East, preparations are underway to export some of our super spec capacity as part of our hub strategy. Current plans have one rig moving overseas in the coming months with additional rigs possible, depending on the speed of the opportunities that develop in the Middle East compared to other competing international locations. Establishing our Middle East hub is an important step in expanding our presence in that region as part of a longer-term growth strategy. Our scale and digital technology not only enhance profitability in our North American solution segment but are also crucial elements for our goal to grow internationally. There is a scarcity of digital solutions being applied in key energy-producing regions around the globe, and developing ways to integrate new technologies will ultimately lead to improved economic returns for all our stakeholders over time. In our offshore Gulf of Mexico segment, our people continue to deliver great value for our customers. As mentioned on the last call, we are implementing pricing improvements offshore and have made significant progress. We expect the margin contribution to continue to improve going forward at moderately higher levels. In closing, it is encouraging to see the industry rebound. However, it should also remind us of past cycles driven by elevated commodity prices and how the drilling industry repeatedly responded by adding capacity, which then led to an oversupplied market. So far, this cycle seems different from both an operator and a service industry perspective. The plan at H&P is straightforward: safety above all, value creation for customers, and margin growth, getting paid for the value we provide. I'm encouraged by the achievements through the dedication of our employees, their passion, and their service attitude they bring to the company. We all strive to deliver excellence each day to enhance the value we provide to our customers and our shareholders. As we move forward, I'm confident our shared values and commitments will endure and enable the company to maintain its leadership position within the oil service industry. And now I'll turn the call over to Mark.

Thanks, John. Today, I will review our fiscal third quarter 2022 operating results, provide guidance for the fourth quarter of fiscal year 2022, and look forward a bit to fiscal year 2023 while commenting on our financial position. Let me start with highlights for the recently completed third quarter ended June 30, 2022. The company generated quarterly revenues of $550 million versus $468 million in the previous quarter. As expected, the quarterly increase in revenue was due primarily to increased revenue per day in our North America solutions segment as we have continued to increase pricing for drilling activity. Total direct operating costs incurred were $377 million for the third quarter versus $341 million for the previous quarter. The sequential increase is attributable in part to the higher average North American solutions rig count compared to the second quarter. General and Administrative expenses totaled approximately $45 million for the third quarter, lower than our previous quarter but still in line with our expectations. During the third quarter, we incurred losses of $17 million related to the fair market value of our non-drilling investment, which is reported as part of gains and losses on investment securities in our consolidated statement of operations. Our fiscal year-to-date gains on the non-drilling investment are approximately $48 million. To summarize this quarter's results, due in part to the execution of our strategies to align pricing with value delivered, as well as disciplined cost management, we had our first positive net income quarter in 10 quarters, earning a profit of $0.16 per diluted share versus incurring a loss of $0.05 in the previous quarter. Third quarter earnings per share were negatively impacted by net $0.11 per share of select items as highlighted in our press release, including the loss on investment securities that I just mentioned. Absent the select items, adjusted diluted earnings per share was $0.27 in the third fiscal quarter versus an adjusted loss of $0.17 in the previous fiscal quarter. During the second fiscal quarter, capital expenditures for the third quarter of fiscal 2022 were $70 million, sequentially ahead of last quarter's $60 million. This is lower than our expectations for the third quarter, but we are still comfortable with the annual range of $250 million to $270 million that was previously provided. H&P generated approximately $98 million in operating cash flow during the third quarter, which is up over $70 million on a sequential basis from the $23 million in the previous quarter. I'll have additional comments about our cash flows and working capital later in these remarks. Starting with our free segments, beginning with the North America solutions segment, we averaged 174 contracted flex rigs during the third quarter, up from an average of 164 flex rigs in fiscal Q2. We exited the third fiscal quarter with 175 contracted rigs, which was in line with our previous guidance. We added four rigs to our active rig count in the third quarter, including three walking flex rig drilling rig conversions that were completed in fiscal Q3. Revenues were sequentially higher by $77 million due to pricing increases for our flex rigs in the spot market, as John mentioned, and as we discussed on the second fiscal quarter call. Segment direct margin was $168 million, just above the top end of our April guidance and coincidentally higher than second quarter fiscal 2022's $114 million. Overall effects from the North America solutions segment increased on a sequential basis due primarily to the increase in average rig count. In addition, reactivation costs of $6.5 million were incurred during Q3 compared to $14.2 million in the prior quarter. Roughly half of these reactivation costs were for the three walking rig conversions added this quarter, with the balance related to additional reactivation costs for rigs deployed at the end of the March quarter. Total segment per day expenses, excluding reconditioning costs and excluding reimbursables, decreased to $15,490 per day in the third quarter from $50,030 per day in the second quarter. Looking ahead to the fourth quarter of fiscal 2022 for North America solutions, as of today's call, we have 176 flex rigs contracted, and we expect to continue at that level through the end of the fourth fiscal quarter of 2022. As we stated last quarter, and much like our competitors are doing, we intend to maintain our CapEx budget for the fiscal year, which translates to holding the line on rig reactivations. Our current revenue backlog from our North America solutions fleet is roughly $629 million for rigs under term contract. Approximately 65% of the US active fleet is on a term contract, and we added approximately 10 rigs to our term roster early in the quarter that had previously been under negotiation for some time. Between now and the end of the calendar year, we have over 60 rigs rolling off of term contracts, which we expect to reprice in the current market. The tight super spec rig supply dynamic is creating pricing momentum, and we expect the percentage of the US fleet on term to decrease to between 50% and 60% during the next few quarters. As I mentioned last quarter, significant inflationary pressures in calendar 2022, together with supply chain constraints, are increasing consumable inventory costs. Such increases are included in our fourth guidance. Note that these costs for consumables and materials and supplies inventory make up less than 25% of the daily operating cost on a rig, with the balance primarily driven by labor. In addition to the inflationary pressures on costs, constraints on supply chain capacity are increasing. Regarding supply chain access to parts and materials, we continue to utilize our proactive approach of detailed inventory planning, scale leverage, and healthy vendor partner relationships to alleviate supply chain challenges in order to avoid a material impact on ongoing operations. We remain in close communication with our suppliers and have placed advanced orders for items in higher risk categories. Approximately 70% to 75% of our daily costs are labor-related. We implemented a wage rate increase in December 2021. Our turnover rates remain consistent with our historical turnover rates. To date, we have not experienced any loss of drilling time or lost contracts due to crewing issues. We are monitoring field labor rates as well as job-required out-of-pocket expenditures. As needed, we'll respond to market conditions to assist in talent retention and attraction. As a reminder, our contracts are structured to pass through labor-related increases over a 5% threshold. We have commenced some early reactivation activities for rigs to deploy in fiscal year 2023 to minimize supply chain constraints where possible and are for planning. Specifically, we are incurring costs already for components of some of the rigs expected to be deployed in the first quarter of fiscal 2023. Reactivation costs will continue to increase due to inflation, but also because the average idle super spec rig has been stacked for two-plus years. Our expectation is that reactivation effects costs will approximate around $1 million per rig moving forward. In the North America solution segment, we expect direct margins to range between $185 million to $205 million, inclusive of the effect of about $6 million in early reactivation costs for the fourth fiscal quarter. Regarding our international solutions segment, international solutions business activity increased to nine active rigs at the end of the third fiscal quarter. As expected, we added two rigs in the Vaca Muerta region of Argentina this quarter and one rig in Colombia. Also as expected, we incurred expenses associated with the rig startups mentioned, as well as investments made to establish our Middle East hub. As we look forward to the fourth quarter of fiscal ’22 for international, we expect to add two more rigs in the Vaca Muerta region of Argentina this quarter as well as a third rig in Colombia. These additions will bring our total active international rig count to 12 at the end of the fourth fiscal quarter if the projected startup timing is adhered to. We also expect to incur more expenses as we further develop our Middle East operations, inclusive of preparation to export a super spec flex rig targeted at regional drilling opportunities. Aside from any foreign exchange impacts, we expect to have between $4 million and $7 million direct margin contribution in the fourth quarter, due in part to sequentially higher average activity, reduced startup expenses, and rate increases. Turning to our Gulf of Mexico offshore segment, we still have four of our seven offshore platform rigs contracted and two of our three management contracts on customer-owned rigs are still unfilled for drilling rates. Offshore generated a direct margin of about $8.7 million in the quarter, which was toward the high end of our expectations. Looking toward the fourth quarter of fiscal ’22 for the offshore segment, we expect total offshore to generate between $9 million and $11 million of direct margin, a sequential increase resulting from contractual pricing increases on our active Gulf of Mexico platform rigs and management contracts, as John mentioned earlier. Now, let me look forward to the fourth fiscal quarter update and full fiscal year ‘22 guidance as appropriate and look ahead to fiscal ‘23 planning. As mentioned, we still expect capital expenditures for the full fiscal year to range between $250 million and $270 million, with remaining spend of approximately $85 million at the midpoint to be incurred in the last fiscal quarter. As a reminder, the timing of some spending has pushed into the second half of the fiscal year as key suppliers continue to rebuild capacity that was taken offline during COVID restrictions and the coinciding energy downturn. Looking forward to our fiscal 2023, which begins October 1, while our budget process is still at an early stage, we have done some preliminary work to help frame up expectations going forward. With that said, you should think about our North America solutions segment's CapEx in three buckets: maintenance, reactivation, and conversion. Our bucket of maintenance capex costs will likely push to the high end of our historical range of $750,000 to $1 million proactively due to inflationary cost increases. The rig-specific reactivation CapEx budget is emerging for 2023 as we get deeper into the idled stack of rigs. One-time capital expenditures will be incurred to overhaul components that we optimized for use during the protracted downturn. For example, to delay an overhaul expenditure, we swapped out components from idle rigs during the downturn that had more time remaining before an overhaul was required. This was done to save capital and defend a conservative balance sheet. Such discreet reactivation CapEx could range from $1 million to $4 million for each rig reactivation in fiscal 2023, depending on the particular componentry involved. Over the next few months, we will refine our planning for next fiscal year, intending to only reactivate rigs for pricing in terms and ensure a return on the significant capital investments required to bring the rigs back online. The final bucket to consider is a conversion bucket, which relates to the continuation of our walking reconversion program. Consistent with how we have been converting rigs to walking capabilities depending on customer demand and projected returns, we will likely do so in fiscal 2023 at a pace of approximately one per month. Our expectations for general and administrative expenses for the full fiscal year 2022 are still expected to be just over $180 million. Items impacting our tax provision and income are at levels resulting in wide variability in the estimated effective tax rate, and therefore, the effective tax rate for upcoming quarters may be volatile. That being said, the US statutory rate for fiscal year 2023 is 21%. We also expect incremental state and foreign income taxes in permanent tax differences to impact our provision. There is no change to the previously guided range of anticipated cash tax of $5 million to $20 million for this fiscal year. Now looking at our financial position, Helmerich & Payne had cash and short-term investments of approximately $333 million as of June 30, 2022, compared to approximately $350 million as of March 31, 2022. The expected sequential decrease was largely attributable to our investment in Galileo during the quarter by $33 million, as mentioned during the previous quarter call. Including revolving credit facility availability, liquidity was approximately $1.1 billion as of June 30. Our debt-to-capital ratio at the quarter end was about 17%, and our net debt was approximately $209 million. We expect our trailing 12 months gross leverage to decrease to our goal of less than two times outstanding debt by September 30, 2022. Following our resumption of positive cash flow generation from operations in fiscal Q2, the growth of that generation in the third quarter is primarily a result of the good pricing work discussed earlier and less reactivation expenditures, as rig counts remained relatively steady in North America solutions segment as we planned on the working capital front. Our accounts receivable grew by $68 million to approximately $398 million as of June 30. The preponderance of our AR today continues to be less than 60 days outstanding from the billing date. Although accounts receivable are up primarily due to price increases in North America solutions, several additional international rigs are working and general pricing increases in the offshore segments. During the third fiscal quarter, we had a couple of significant cash-related transactions. First, as mentioned in last quarter's call, we invested approximately $33 million in Galileo. Second, we sold our legacy Schlumberger stock for approximately $22 million in pre-tax proceeds. We still expect to have between $350 million and $400 million of cash and short-term investments on hand by the end of the fiscal year, although we expect to be toward the bottom half of that range due to some working capital lockup from accounts receivables, as I mentioned. As we expected, the growth in accounts receivable in the fiscal year provided a platform for cash generation in the second half of the year. To that point, in the recently completed third quarter, we fully covered our maintenance CapEx with cash flow from operations, as well as funded our regular dividend. Further, our disciplined capital planning and operational execution excellence sets the stage for cash increases going forward. Cash returns to shareholders remain a top priority with our existing dividend, and we seek to augment these returns in the future. Additional returns are not yet determined by our board of directors but could consist of an assessment of our long-standing regular dividend, a potential variable type dividend, and opportunistic share buybacks. As mentioned in the press release, our financial stewardship compels us to take a measured approach in balancing our maintenance CapEx requirements, growth capital opportunities for both reactivations and international expansion, and potential additional shareholder returns. More to come on this in fiscal 2023, in the coming quarters call. Note, this concludes our prepared comments for the third fiscal quarter. Let me now turn the call over to Ashley for questions.

Operator Instructions. And we'll take our first question from Derek Podhaizer with Barclays. Please go ahead. Your line is open.

Hey, good morning, guys. Just wanted to get more of a sense on how many rigs you could add to the market next year. I know your conversations with your customers. You mentioned in the skidding to walking conversion program and the breakdown of the CapEx about one per month, call that 12. Just what else do you think you can add to the market just based on your conversations and based on the demand that they're all within keeping in your framework of generating the returns based on the amount of CapEx and OpEx needs to be to deploy to player. I just love a little more color on that.

Yes, Derek. I can give you some sense of that. As Mark said, we're really not in a position other than to just mention the 12 walking conversions, assuming the demand and the margins returns are there. One way to think about it is what you expect the rig count to do in the super spec space next year. I would say starting in calendar Q4 of this year, because again, as I said earlier, that's kind of been the buying season over the last two years. So if you make an assumption that 75 rigs to 100 rigs get added over that 12-month period starting in Q4, if you look at our 25% market share, that would be a reasonable range to think about. But again, I think the main point I want to get across is we're not making decisions based on market share. We're making decisions based on the returns that we can generate from these rigs and just ensuring that we're getting reasonable rates of return over a long period of time. So, Derek, does that answer your question?

Yes, that's helpful. You mentioned that $30,000 per day or above represents 20% of your fleet currently. Given your visibility and the rigs approaching contract term, how can we increase that to 40%? Can you explain the timeline and process involved in getting the entire fleet to reach that $30,000 or more on our daily rate?

Yes. And if it's not clear in the prepared remarks, but that 20% was effective at the end of our fiscal Q3. That's not where we are today necessarily. So that's our Q3 fiscal Q3 number, we don't have we have pretty clear insight into that. It does take a couple of quarters to get there. So, I don't think I've really said anything about what that timing would be. I think, reasonably speaking over two or three quarters, probably process-wise wouldn't would enable us to get to that level of pricing, low, low 30 pricing. I think that's exactly right, a couple more quarters because as you said, that was in the June 30 number you gave in prepared remarks. And here, we are not far beyond that, and we're already seeing meaningful accretion to that number a month later.

Got it. That's very helpful. Appreciate the color guys sort of back.

And we'll pick the next question from Douglas Becker with Benchmark Research. Please go ahead. Your line is open.

Thanks. John, I wanted to get your thoughts on a conceptual question. Investors historically have thought about gain rates reaching a soft ceiling when it comes back to reactivation costs or upgrade costs. It seems like spot rates are getting above some of those levels. We've done a leading-edge basis, but just want to get your thoughts on, is that still a relevant framework to think about pricing? Or have we moved into a different dynamic?

Yes, I think the historical pricing context there is really different today for a lot of reasons. But, I think when you consider the investments that we have in specifically in the super spec capacity fleet, I think most people want to compare today versus a 2014 time period, as an example. As we said in our previous call, that was the last time we had 50% gross margins, but we didn't have 230 super spec rigs in the fleet at that time. So it's a much, much different situation.

Yes, John, I would just add to that. Doug, as I mentioned, in 2014, we didn't have a super spec rig. So going into ‘16 and beyond, we invested a lot of money in the upgrading of the fleet, resulting in the industry's largest super spec fleet, and also resulting in a lot of benefits for our customers. Along the way, we add in a very oftentimes, what we would consider to be suboptimal returns on invested capital compared to our weighted average cost of capital. So as we were just trying to get back to numbers that makes sense financially, this 50% margin is what will get us there; we're on the journey to get to that.

Now that provides some good context. Maybe more succinctly. It doesn't sound like you expect a meaningful increase in capacity if spot rates are $35,000 a day or higher because of the framework you've just laid out. Is that fair to say?

Then again, it was not clear.

Sure, just trying to gauge it. rectification if we see $37,000 a day spot day rate? Do we see a big influx of capacity coming into the market?

Yes, I think the capacity that is out there, as we described, we're estimating around 130 super spec rigs. We know there are other drillers that are looking at doing some upgrades to SER tech rigs in order to satisfy demand. Guy, I would be surprised personally to see all of those rigs reactivated in 2023 for a number of reasons that we've already talked about related to supply chain and the capability to be able to provide the equipment sets required to get those rigs back into working condition, because we as an industry we've utilized equipment sets off of those rigs that have been idle now, as Mark said, for over two and a half years. And so I, personally, I don't think there's going to be a response; we've had some people ask about new builds. And I just think that, based on what Mark just said in terms of a $30 million to $35 million price tag for a new rig, I don't think that's going to be the case either.

Yes, take the midpoint $32.5 million, if you're making $15 a day margin, that's a six-year payback. Or if you're making $20,000 a day margin, that's a four-and-a-half-year payback. And then with the customer base today that has little appetite to contract up beyond their fiscal budget year. So yes, I think the supply chain thing, as John mentioned, is actually a significant hurdle. For any, we're working with our scale and leverage with our suppliers to make sure that we can put rigs back to work and also keep the active fleet in good working condition. And that's an effort that's a lot different today than it was at any time over the last 10 years.

Great. And Doug, it really goes back to just capital discipline. We've talked about that; that's really the rallying cry within the industry. Our customers are demonstrating it. The service industry is displaying that and there's no reason to rush, even if the supply chain were there, there's no reason to rush to try to capture all this, any additional market share that you might be able to capture. One of the things that we experienced in this last quarter, and you heard us talk about churn, we actually had 18 rigs that were given back to us for various reasons: customers, going through their budget too fast, acreage position, the list goes on and on. 18 points of demand that historically speaking as an industry, we would have tried to satisfy that demand by reactivating something. And so, last quarter, we said, we're going to 175. And in Q3, we're going to finish the year at 176, we're within our capital budget; that wouldn't have been the case in previous cycles. We would have continued to try to capture additional share. So I think that's a really distinct difference in our industry, which I think is really healthy, it's healthy on the operator side and healthy on the overall service side as well.

Thank you very much.

Next question is from the line of Keith Mackey with RBC, please go ahead. Your line is open.

Hi, good morning, and thanks for taking my questions. Just wanted to maybe start out with the contracting nature. Are you seeing any increased appetite for longer-term contracts from customers that are not necessarily associated with conversion or upgrade or those hot rigs or whatever you'd like to call them still on shorter-term durations?

Keith, I would say it's a mix. We have customers that are interested in terming up rigs or a portion of their fleet, particularly larger customers that may have 10 rigs or 15 rigs running. I'm making this up, 10 rigs or 15 rigs running. They don't necessarily want to term up every rig, but they may want to term some summary. From our perspective, as Mark said, we've got 60 rigs approximately that are rolling off term the next couple of quarters. And, we'll be looking at those very, very closely in terms of whether those remain in term or rollover into spot; I would say most of those rigs are going to probably go into a more spot type market. But I think it's really a mix that we see customers across the board, some that want to lock up on term, some that would prefer to play the spot market.

Got it? Thanks for that.

I would just add for us at this time, with the upward momentum in pricing and supply-demand dynamics of the sector, trying to get to the returns that we have been discussing. Putting more of our market into the upward mobility of the spot pricing makes sense.

Got it, that's helpful. Just curious if you can give us a little bit more detail on the number of rigs you have that could be reactivated within that one to $4 million CapEx range. And maybe just your little more on your confidence in being able to get additional rigs to the market in early fiscal or calendar 2023 given the supply chain?

Well, we have from a reactivation standpoint, we got into some of the supply chain work that we're doing in this fourth quarter to get ready for putting some rigs back to work. But it's too soon to know definitively how many we will put into the market. As John mentioned, we're being very cognizant about capital discipline, and two, we're not going to try to meet every demand point that comes our way because we know there will be the existence of churn in the market. In other words, rigs freeing up for whatever may be a contractor, I mean, an H&P running out of budget, H&P running out of acreage. Many dynamics, we will meet every single demand for me to that makes sense. So we're still trying to balance; I don't know the last two years in the buying season at the end of the calendar year Q4 before the calendar Q1, 40 rigs and 44 rigs, these are the last two buying seasons for us to be at and we don't see that level of addition coming. You have to remember that in those two seasons, we were coming off from a substantially low bottom through both the OPEC price change and the pandemic that began in March of 2020. So a substantial bottom to come back up from; we're approaching numbers from March 1, 2020 today from an activity level standpoint, so don't see the quantum of additions. So differently do not see the quantum of additions coming, that we had the last few buying seasons. So I don't know specifically what that'll be yet. We are working, though, to know what every single one of our approximately 54 remaining is in perspective takes. But not ready to comment on delineating the numbers for all for those.

Got it? No, that's helpful. Thanks very much. I'll turn it back.

And we'll take our next question from Andrew Herring with JP Morgan, please go ahead.

Thank you. Good morning. So I'm going to turn to the international outlook. So it sounds like in the near term, you're reactivating a few rigs or adding a few rigs in Argentina and Colombia, and then transferring one into the Middle East. Can many of you comment on the outlook on some Middle East growth in activity? Do you think customers are looking for more demand before the end of calendar ‘22? And initial insights into what we might expect in 2023?

I'll start, John, if you want to chime in. I think as we think about it, we're looking more over the next two to three years in our planning horizon. So if you think about it, we're always looking at a five-year planning horizon; we consider the Middle East scale to be more mid-cycle in that horizon. So we're preparing really our Middle East hub, which is to be able to simply have an operating presence in the structure and the Gulf Coast countries. We can respond to demand points that we see coming in at mid-cycle horizon. We are excited about several opportunities we have, part and parcel to the brand presence that we've benefited from after the addenda I can bet in the last year. We're participating in many bid tenders in the region with NRCS and IOCs alike. So it's a little too early to say if we might be successful in one of those tenders. If we were fortunate enough to win two, that may add three to six rigs per bidding effort. So if we were fortunate enough to win two that might be three to six rigs in the next couple of years, is that the way to think about it. And in particular, the flex rigs that we have, are with our, we've drilled more shale wells than anyone else globally, frankly. And taking that expertise, especially in some of the burgeoning gas plays in the region, is a really good way to help the customer achieve their goals. So those are the sorts of things we're interested in. John, any other comments?

No, I think we've talked about unconventional opportunities for really, we've talked about it internationally for many years. We're starting to see evidence that we're hoping is going to come to fruition. So I would just add to that. And I think our fleet is really designed for unconventional work. The performance, reliability, and technology solutions that we have, all of those are really complementary to that opportunity set.

Great, thank you. That's very helpful. And as a follow-up then on the economics internationally, understanding it might be a little early to comment on the Middle East. But assuming these will be more creative contracts, you're talking about comparing the US to prior cycles. To what extent is that helpful in our modeling for internationally comparing to prior year margins you've been able to achieve on these risks? With a higher technology, can we see that exceed those levels, just any comment you could, help us kind of gauge where we can see margins tend to be helpful?

Well, each one of these dinners, for example, that we're participating in, the economics have to be right for us. Our own history over the last couple of years in International is not a we're not looking to that as any sort of guidance because of the crazy volatility and actually a wind-down to zero rigs working because of the pandemic. But as we move forward, these things have to be accretive and we look at the financial returns through time. We also look though, at the ability to build scale. So if we want to win an initial bid with three rigs, we will be looking beyond that singular bid as a potential new entry point for a new customer for H&P, looking to see what the potential might be for that customer to scale that up. Really get better absorption rates like we do here in the US through our scale. So we're looking at a lot of different components. But I think easy to say that it would have to be financially feasible.

Thanks. That’s all for me. I’ll turn it back.

Hi, we'll take our next question from Tom Carstairs with Stifel Research, please go ahead. Your line is open.

Good morning. I want to know when it comes to the remaining inventory of idle and redeployable super spec rig fleet of 54. There's been a lot of emphasis placed on what you're trying to achieve with regards to converting the psychology around pricing, hitting new levels for leading edge day rate and the associated gross margin. But on the terms and conditions side, are you now expecting or do you think you might be able to get some minimal term or take-or-pay conditions, maybe an early termination provision? Just wondering how good the remainder of the reactivation contracts might be that we could see?

Well, in the US, we will. As I mentioned earlier, we see a movement down from 65% to 40% to 50% to 60% range for term. For everything we enter into in the US on term, Tom, we do get that take-or-pay cancellation provision. Having said that, where we are today, financially is much different than where we were coming out of a couple of two or three of the more recent downturns. What I mean by that is we have one debt due in 2031. We have a base dividend at 65 compared to lower than it was going into the pandemic. We have substantial cash on hand and look to grow. So our capital structure requirements for such take-or-pay provisions are less necessary than they might have been in prior cycles. But we still always like to have some defensiveness, which is why we're still going to remain within that 50% to 60% target range. But give up some term to try to capitalize on the supply demand dynamic that is creating this push up in pricing and therefore margins for us. John, any other?

Yes, it's always about balance. There will be some of our walking conversions, or probably most of our walking conversions that we will have a term contract commitment. But as I said earlier, Mark mentioned we're going to have 60 rigs rolling off of term contracts over the next couple of quarters. I would imagine most of those are going to roll into a spot market. We will have some certainty on returns on a larger recommission of the conversions. But as Mark said, we're positioned really well to be able to manage through that.

Got it, helpful clarifications. And then I just wanted to get an update on auto slide, that the percentage of your average active rig fleet for the quarter of 174 rigs, what percentage of that count used auto slide at any point over the course of the quarter?

I think we're around 25%. I believe that's right. And we continue to have had uptake; it's been really well received in providing automated directional drilling capacity. And as the rig count grows, it becomes even more important because we're bringing a lot of directional drillers back into the space. Obviously, they don't have the experience that a lot of operators would like to have. But just being able to automate that process, directional drilling processes, is a huge win. We're also able to tie that into a commercial performance-based model. That's really a win-win situation for each, H&P and for our customer.

And would you say that the 25% that used auto slide at some point, does that 25% contain the entirety of the 20% of the fleet for the quarter that realized average revenue per day $30,000 or greater?

We don't have. That's a great question. I don't have that data. I do know that there is a portion of that included in that. But I don't have the data for if it's only 20%, or some subset of that.

Right. I assume the overlap would be high. It's not a perfect Eclipse. But okay, thanks for taking my questions.

Another question from John Daniel of Daniel Energy Partners, please go ahead.

Guys, thanks for including me. John and Mark, I think most of us have talked ourselves into believing this is a multi-year upcycle. And assuming and hoping that's right. I'm just curious as you look at the pricing, we keep hearing about the low mid-30s in terms of leading edge. But the rig count, if we actually, as an industry add, call it 50 to 100 range over the next 12 months. Where does pricing go to?

Well, John, obviously pricing has moved very, very quickly. It needed to move very, very quickly. There was a huge disconnect in the value proposition that we provide, the investments that we have, and the margin generation. If you just look at previous cycles, obviously since 2014, we have not been able to get back to that. So right now we're seeing leading edge mid-30s. Our goal, as we've already said, is to get to the low 30s. That's really our focus right now on getting to 50% gross margin. It's really hard to say past that, John, I mean, we all read the same materials after that. And there's a lot of people that are surmising where it's going. Obviously, we've got a pretty good glimpse into that. But right now, we're just sticking to the goals that we've laid out there. And we'll see where it lands.

At this point, have you had any shareholders that have advocated pushing activity over price?

No, we haven't been unanimous.

Yes, got it.

I think there's some that haven't completely followed from our last call that we said, hey, our rig count is going to be at most 176 rigs this fiscal year. And that was called a quarter ago. But again, we're really pleased because at the beginning of the year, we thought that same $250 million to $270 million was for 160 rigs; we're able to get 176 out of it. So created some great efficiencies there. But expect to continue to see that from us. I think that's what shareholders want; that's what investors want. Very much like our customers are doing.

I got two quick ones. And I'll wrap up. If you said this, I apologize, but I kind of you have a range of where you might exit calendar Q4 in terms of a contracted rig count calendar Q4.

Now, as we said, we're working on reactivations; it's a little too far out to know the definitive demand points. And as we alluded to earlier, we will not meet every one of them.

Right.

So still too early, John.

We would be. And again, I think going back to the question John asked a minute ago, I think some folks who may not have heard the 176 for the September 30 goal in holding rigs tight, in CapEx tight, which is helping the dynamics of supply demand and helping pricing. I think that was more on the analyst side. But when we speak to investors and long-term investors, there's not a single one of them that we've talked to with any sort of share over margin.

Yes. Okay. Well, I'm glad your shareholders are thinking wisely. You've been very generous with your time. It's coming up on the end of the hour, and I'll turn it over for anyone else and follow up with David afterwards. Thanks.

Thank you, Ashley. And thanks to all of you for joining us today. We know there are a lot of earnings calls going on today, and we really appreciate your time. I will tell you the H&P team, we've already said it we're laser-focused on delivering value to customers and to shareholders. We aim to deliver value to customers through top-tier performance, safety and reliability and to our shareholders, continued improvement in our margin growth and our return. So thank you again for your time and have a great day.

Thank you. This does conclude today's program. Thank you for your participation. You may disconnect your lines.