Helmerich and Payne Inc (HP) 2022 Q3 法說會逐字稿

Good day, everyone, and welcome to today's Helmerich & Payne Fiscal Third Quarter Earnings Call. (Operator Instructions) Please note this call may be recorded, and I will be standing 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's conference call and webcast for the third quarter of fiscal year 2022. 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 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 are not guarantees of future performance. A 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 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 Lindsay.

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 change to include 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. And in our third fiscal quarter, we had roughly 20% of our fleet's 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 FlexRig fleet 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 Solutions segment. Fiscal discipline and contractual churn allowed us to recontract 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 put a damper on the industry's ability to reactivate idle super-spec rigs at significant scale during the buying season the last 2 years that has been 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 FlexRigs is extremely tight.

We are seeing some customers looking to add incremental rigs for 2023. The needs are typically in the range of 1 to 4 rigs, and there are some looking to replace a lower-performing rig with FlexRig. While we are unable to comment on the number of rigs that we could add specifically today, it is important to underscore that going forward, we will apply the same disciplined focus on financial returns and on receiving commensurate compensation for the value we are providing.

Along those lines, Mark will provide some high-level remarks on our fiscal 2023 CapEx response to potential future demand for our rigs -- for rigs in our idle super-spec luxury fleet. We continue to hear about the benefits our customers experience from our digital technology solutions, especially when combined with our uniform FlexRig fleet. We continue to hear about the benefits our customers experience from our digital technology solutions, especially when combined with our uniform FlexRig fleet.

As horizontal wells continue to trend toward greater complexity and longer lateral lengths, drilling efficiency and reliability are important factors that differentiate our premium super-spec service offering.

On the international front, activity is ticking higher with further improvements in our South American operations and the potential for more activity in 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 Solutions segment, but we believe these are also crucial elements in 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. But 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, update full fiscal year '22 guidance as appropriate, look forward a bit to fiscal 2023 and comment 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 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 America Solutions segment 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 ADNOC Drilling investment, which is reported as a part of gains and losses on investment securities in our consolidated statement of operations.

Our fiscal year-to-date gains on the ADNOC 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. H&P earned 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 a 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 these select items, adjusted diluted earnings per share was $0.27 in the third fiscal quarter versus an adjusted loss of $0.17 during the second fiscal quarter.

Capital expenditures for the third quarter of fiscal '22 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 will have additional comments about our cash flows and working capital later in these remarks.

Turning to our 3 segments, beginning with the North America Solutions segment. We averaged 174 contracted FlexRigs during the third quarter, up from an average of 164 FlexRig in fiscal Q2. We exited the third fiscal quarter with 175 contracted rigs, which was in line with our previous guidance. We added 4 rigs to our active rig count in the third quarter, including 3 walking FlexRig drilling rig conversions that were completed in fiscal Q3. Revenues were sequentially higher by $77 million due to pricing increases for our FlexRigs 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 sequentially higher than the second quarter of fiscal '22's $114 million.

Overall OpEx 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 3 walking rig reconversions added this quarter, while the balance related to additional reactivation costs for rigs deployed at the end of the March quarter. Total segment per-day expenses excluding recommissioning costs and excluding reimbursables, decreased to $15,490 per day in the third quarter from $15,030 per day in the second quarter. Looking ahead to the fourth quarter of fiscal '22.

For North America Solutions. As of today's call, we have 176 FlexRig 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 --remain within 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 U.S. active fleet is on a term contract. Of note, we added approximately 10 rigs to our term roster early in the quarter, which had previously been under negotiation for some time. Between now and calendar year-end, 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 aiding pricing momentum and we expect the percentage of the U.S. 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 forward guidance. Note that these costs for consumption and materials and supplies inventory today 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.

In regard to 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 to our 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 lost drilling time or lost contracts due to crewing issues.

We are monitoring the field labor rates as well as job-required out-of-pocket expenditures, and as needed, we will 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 in our forward planning. Specifically, we are incurring costs to ready components of some of the rigs expected to be deployed in the first quarter of fiscal 2023. Reactivation costs will continue to increase given inflation, but also because the average idle super-spec is stacked for 2-plus years. Our expectation is that reactivation OpEx costs will approximate $1 million per rig moving forward.

In the North America Solutions 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 full fiscal quarter.

Regarding our International Solutions segment, International Solutions business activity increased to 9 active rigs at the end of the third fiscal quarter. As expected, we added 2 rigs in the Vaca Muerta region of Argentina this quarter and added a second rig in Colombia.

Also, as expected, we incurred expenses associated with the rig start-ups that I just 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 2 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 start-up timing is adhered to. We also expect to incur more expenses as we further develop our Middle East hub, inclusive of preparation to export a super-spec FlexRig that will be targeted at regional drilling opportunities. Aside from any foreign exchange impacts, we expect to have between $4 million to $7 million direct margin contribution in the fourth quarter, due in part to sequentially higher average activity, reduced start-up expenses and rig rate increases.

Turning to our Gulf of Mexico -- Offshore Gulf of Mexico segment. We still have 4 of our 7 offshore platform rigs contracted and 2 of our 3 management contracts on customer-owned rigs are still on full drilling rates. Offshore generated a direct margin of about $8.7 million during the quarter, which was toward the high end of our expectations. As we look toward the fourth quarter of fiscal '22 for the offshore segment, we expect the total offshore that we expect that offshore will generate between $9 million to $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 full fiscal year '22 guidance is 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 to the second half of the fiscal year as key supplier has continued to rebuild capacity that was taken offline hearing 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 CapEx of the 3 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 per active rig due to inflationary cost increases. The rig-specific reactivation CapEx budget emerges for 2023 as we get deeper into the idled stack of rigs. Here, onetime capital expenditures will be incurred to overhaul componentry that we optimally utilize in the protracted downturn. For example, to delay an overhaul expenditure, we swapped out like equipment from idle rigs during the downturn that had more time remaining before an overhaul was required. This was done in an effort to save capital and defend their conservative balance sheet. Such discrete 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 with the intent of only reactivating rigs for pricing and terms that ensure a return on the significant OpEx and CapEx investments required to bring the rigs back online. The final bucket one should consider as a conversion bucket, which relates to the continuation of our walking reconversion program. Consistent with how we have been converting the rigs to walking rig capability 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 '22 year are still expected to be just over $180 million. Items impacting our tax provision and income are at levels that result in a wide variability in the estimated effective tax rate. And therefore, the effective tax rate for upcoming quarters may be volatile. With that being said, the U.S. statutory rate for fiscal year '21 is 21%. In addition, we are expecting incremental state and foreign income taxes and permanent book-to-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 at June 30, 2022 versus an equivalent of $350 million in March 31, '22. The expected sequential decrease was largely attributable to our investment in Galileo in the quarter for $33 million, as mentioned during the previous quarter call.

Including our revolving credit facility availability, liquidity was approximately $1.1 billion at June 30. Our debt to capital at quarter end was about 17%, and our net debt was $209 million approximately. We currently expect our trailing 12 months gross leverage churn to reach our goal of less than 2x 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 stems primarily from a result of the good pricing work discussed earlier and also due to less reactivation expenditures, as rig counts remained relatively steady in the North America Solutions segment as planned.

On the working capital front, our accounts receivable at March 31 of $330 million, grew by $68 million to approximately $398 million at June 30. The preponderance of our AR today continues to be less than 60 days outstanding from billing date, although absolute dollar receivables are up primarily for price increases in North America solutions, several additional international rigs working and gene price increases in the offshore segment. During the third fiscal.

Quarter, we had a couple of significant cash-related transactions. First, as I mentioned in last quarter's call, we invested approximately $33 million in Gallileo; second, we sold our legacy Schlumberger stock for approximately $22 million in pretax proceeds. We still expect to end the fiscal year with between $350 million and $400 million of cash and short-term investments on hand. Although we expect to be towards the bottom half of that range due in part to some working capital lockup from accounts receivables, as I mentioned. As we expected, the growth in rig count early 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, where 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 accretion going forward.

Cash returns to shareholders remains a top priority with our existing dividend and we have a desire 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 and balance our maintenance CapEx requirements, growth capital opportunities for both U.S. reactivations and international expansion and potential additional shareholder returns. More to come on this for fiscal 2023 and the coming quarter's call.

Note that 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.

I just wanted to get more of a sense on how many rigs you could add to the market next year? I know you're in conversations with your customers. You mentioned 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 out there, all keeping in your framework of generating the returns based on the amount of CapEx and OpEx that needs to be redeployed. Just would 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 margin 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. And really, I would say, starting in calendar Q4 of this year because of that, again, as I said earlier, that's kind of been the buying season over the last 2 years. So -- if you think about -- if you make an assumption that 75 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 making certain that we're getting reasonable rates of returns over a long period of time. So does that answer your question?

Yes. No, that's helpful. And then you mentioned the 30,000 per day at or above that level, 20% of your fleet on that. Based on the visibility you had and the rates coming up on term and the contract turn, how can we double that to 40%? Just the cadence and how long it would take to get the whole fleet up to that at 30% or above day rate?

Yes. And -- it's not clear in prepared remarks, but that 20% was effective the end of our fiscal Q3. That's not where we are today necessarily. So that's a 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. And so I don't think, Dave, we said anything about what that timing would be. I think reasonably speaking, over a 2 or 3 quarter probably process-wise would enable us to get to that level of pricing, low 30s pricing.

I think that's exactly right, John. couple more quarters. Because as you said, that was the June 30 number you gave in the prepared remarks and the year where we are not far beyond that, and we're already seeing meaningful accretion to that number a month later so.

And we'll take our next question from Doug Becker with Benchmark Research.

John, I wanted to get your thoughts on a conceptual question. Investors historically have thought about day 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, at least on 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, the context there, it's really different today for a lot of reasons. But I think when you consider the investments that we have in the -- specifically in the super-spec capacity fleet, I think most people want to compare today versus a 2014 time period as an example. And as we said in our previous call, that was the last time we had 50% gross margins. But we didn't have a 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, that as John 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 very often times what we would consider to be suboptimal returns on invested capital compared to what our working -- what our weighted average cost of capital is. So as we -- we're just trying to get back to numbers that make sense financially, and this 15% margin is what will get us there. We're on the journey to get to that.

Separately, simultaneously, the rigs we built back then, $20 million of (inaudible) or even sub $20 million in 2014. Today, rough estimates say that somewhere between $30 million to $35 million. So a lot of capital still to be deployed to the idle assets that have been there 2.5 -- 2 years plus, which means when we get to the buying season at the end of this calendar year, the beginning of calendar '23, they'll have been sitting there 2.5 years. So a lot of capital deployed for what we estimate to be nearly 150 super-spec rigs in that 2.5-year idle tenure by the time we get to the end of this calendar year. I hope that helps, Doug.

No, 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?

Can you say that again, Doug.

Sure. Just trying to gauge is your expectation if we see $37,000 a day spot day rates, 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's other drillers that are looking at doing some upgrades to SCR type rigs in order to satisfy demand. Yes, I think 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 just the supply chain and the capability to be able to provide the equipment sets required to get those rigs back into working -- back up to working conditions because -- we -- as an industry, we've utilized equipment sets off of those rigs that have been idled now, as Mark said, over will be for over 2.5 years. And so 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, again, 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 midpoint, $32.5 million, if you're making $15,000 a day margin. That's a 6-year payback or if you're making $20,000 day margin, that's a 4.5-year payback. And 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 or so.

And Doug, it really goes back to just to 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 was 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 rigs that were 18 points of demand that historically speaking, as an industry, we would have tried to satisfy that demand for reactivating something. And so last quarter, we said we're going to 175 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, it's healthy on the oilfield services side as well.

We will go next to Keith MacKey with RBC.

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 -- or are those hot rigs or whatever you'd like to call them still on shorter-term duration?

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

And I would just add, for us at this time, with the upward momentum of pricing and the 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 $1 million to $4 million CapEx range. And maybe just your -- a 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, when we guided to 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'll put into the market. As John mentioned, we're being very cognizant about capital discipline, one; and two, we're not going to try to meet every demand point that comes our way because we know they will lead the existence of churn in the market. In other words, rigs freeing up for whatever reason. It may be a contractor -- I mean an E&P running out of budget, an E&P running out of acreage, many dynamics. We won't meet every single demand for if that makes sense. So we're still trying to balance. I don't -- the last 2 years in the buying season at the end of the calendar year, calendar Q4, calendar Q1, 40 in 44 rigs, each of the last 2 buying seasons for us to be added. We don't see that at a level of addition coming.

You have to remember that in those 2 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 of 2020 today from an activity-level standpoint. So I don't see the quantum of additions, said differently, do not see the quantum of additions coming that we had the last 2 buying seasons. So don't know specifically what that will be yet. We are working though to know what every single one of our approximately 54 remaining super specs takes. But not ready to comment on delineating the numbers draw for the (inaudible).

And we'll take our next question from Andrew Herring with JPMorgan.

I was hoping to turn to the international outlook. So it sounds like in the near term, you're reactivating a few rigs or adding a new few rigs in Argentina and Colombia and then transferring one into the Middle East. I was wondering if you could 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 2 to 3 years in our planning horizon. So if you think about we're always looking at a 5-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 -- if you can just simply have an operating presence and structure in the Gulf Coast countries so that we can respond to demand points that we see coming in that mid-cycle horizon. We are excited about several opportunities we have, part and parcel to the brand presence that we benefited from after the ADNOC investment last year. We're participating in many bid tenders in the region with NOCs and IOCs alike.

So it's a little too early to say if we might be successful in one of those tenders. And if we are, that sort of thing is, say, 3 to 6 rigs per bidding effort. So if we were fortunate enough to win 2, that might be 6 to 12 rigs in the next couple of years, that is the way to think about it. And in particular, the FlexRig that we have with our -- we've drilled more shale wells than anyone else has 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 the unconventional opportunity for -- really, we 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 that's really designed for unconventional work the performance, reliability and the technology solutions that we have, all of those are really complementary to that opportunity set.

Great. That's very helpful. And as a follow-up on the economics internationally, understanding it might be a little early to comment on the Middle East, but assuming these will be more accretive contracts. You're talking about comparing the U.S. to prior cycle. To what extent is that helpful in our modeling for internationally comparing to prior year margins you've been able to achieve on these rigs with the higher technology, can we see that exceed those levels? Just any comment you could help us kind of engage where you can see margins trend here would be helpful.

Well, each -- each one of these tenders, for example, that we're participating in, the economics have to be right for us. Our own history over the last couple of years 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 won an initial bid with 3 rigs, we will be looking beyond that singular bid as a potential new entry point for a new customer for H&P. And looking to see what the potential might be for that customer to scale that up and really get better, better absorption rates like we do here in the U.S. 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 accretive.

We will take our next question from Tom Curran with Seaport Research.

When it comes to the remaining inventory of idle and redeployable super-spec rigs at 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 condition 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 U.S., we will -- as I mentioned earlier, we see a movement down from 65% to more to the 50% to 60% range for term. And for everything we enter into in the U.S. in 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 -- 2 or 3 of the more recent downturns. What do I mean by that? We have one debt that's due in 2031. We have a base dividend that's 65% lower than it was going into the pandemic. We have a substantial amount of cash on hand and look to accrete that. 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 in that 50% to 60% target range, but give up some terms 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 a balance Tom, there will be some of our walking conversions or probably most of our walking conversions that we will have a term contract commitment that as I said earlier, Mark mentioned, we're going to have 60 rigs rolling off of term contract over the next couple of quarters. And I would imagine most of those are going to roll into a spot market. So we will have some certainty on returns on the larger recommission or 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 was wondering if you could give us an update on AutoSlide. The percentage of your average active rig fleet for the quarter of 174 rigs, what percentage of that count you used AutoSlide 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 uptake. It's been really well received in terms of providing automated directional drilling capacity. And as the rig count grows, it is even more important because we're bringing a lot of directional drillers back into the space. And 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 process is a huge win. And then we're also able to tie that into a commercial performance-based model. That's really a win-win situation for H&P and for our customer.

And when you say that the 25% that used AutoSlide at some point, does that 25% contain the entirety of the 20% of the fleet for the quarter that realized average revenue per day of $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 is included in that, but I don't have the data for -- if it's all 20% or some subset of that.

We will go to our other question from John Daniel with Daniel Energy.

John and Mark, I think most of us have talked ourselves into believing, this is a multiyear up cycle 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, we add, call it, 50 to 100 rigs over the next 12 months, where does pricing go to?

Well, John, obviously, there's -- pricing has moved very, very quickly. It needed to move very, very quickly. There was a huge disconnect and the value proposition that we provide, the investments that we have and the margin generation. And if you just look at previous cycles, obviously, we -- 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. And 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 out there, and there's a lot of people that are surmising where it's going. And 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.

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

No.

No. We haven't.

It's (inaudible).

Yes. Got it. We haven't. I mean, I think there's some that haven't -- didn't completely follow from our last call that we said, hey, where rig counts going to be, at the most 176 rigs this fiscal year, and that was a call 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 with 160 rigs, we were able to get 176 out of it. So created some great efficiencies there. But I expect to continue to see that from us. And I think that's what shareholders want. That's what investors want, very much like what our customers are doing.

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

Calendar Q4, no. 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. Still too early, John.

Fair enough. But you would expect to be above 176, I presume, in calendar Q4.

We would be. And it's -- again, I think going back to the question you asked John a minute ago, I think some folks who were maybe not heard the 176 for the September 30 goal and holding rigs tight and 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-only investors, there's not a single one of them that we've talked to that would like (inaudible) share over margin. So we're going to be very cognizant of that theme as we think about your last question and figuring out how many rigs to put in the market in our first fiscal quarter to get to [1231].

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

There are no further questions at this time. I'll turn the call back over to John Lindsay for any closing remarks.

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 that 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 returns. So thank you again for your time, and have a great day.

Thank you. And this does conclude today's program. Thank you for your participation. You may disconnect.