This conference call transcript was computer generated and almost certianly contains errors. This transcript is provided for information purposes only.EarningsCall, LLC makes no representation about the accuracy of the aforementioned transcript, and you are cautioned not to place undue reliance on the information provided by the transcript.
spk03: Good day, everyone, and welcome to today's Helmick and Payne's Fiscal First Quarter Earnings Call. At this time, all participants are in a listen-only mode. Later, you will have an opportunity to ask questions during the question and answer session. You may register to ask a question at any time by pressing the star and 1 on your touchtone phone. Please be advised, this call may be recorded. It is now my pleasure to turn today's program over to Dave Wilson, Vice President. Dave, go ahead.
spk04: Thank you, Christy, and welcome, everyone, to Humber Campaign's conference call and webcast for the first quarter of fiscal year 2021. With us today are John Lindsay, President and CEO, and Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some prepared comments with us, after which we'll open the call for questions. Before we begin our prepared remarks, I'll remind everyone that this call will include forelooking 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. 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 also will be making reference to certain non-GAAP financial measures such as segment operating income and other operating statistics. You will find the GAAP reconciliation comments and calculations in yesterday's press release. With that said, I'll turn the call over to John Lindsay.
spk02: Good morning, everyone, and thank you for joining us today. With one month behind us in 2021, we find ourselves with a combined sense of relief and optimism, relieved that one of the most difficult years in the company's 100 year history is behind us and optimistic considering the market share gains accomplished during the first fiscal quarter of 2021 and strengthening oil prices, which enhance the financial health of our customers. We entered the new year with 94 rigs running in US land. That's double the number we had in August and the upward trend continues. Around this time last year, WTI prices were trading in the low 50s. There were approximately 800 rigs operating in the U.S. land market, and H&P was operating 194 of those rigs. Contrast that with today, where oil prices are up over 10% up into the upper 50s, and the industry rig count is approximately 415 rigs, and H&P is running 103-flex rigs. Obviously, a lot has happened between these two data points, and it shouldn't surprise anyone that the short- and medium-term activity outlook from E&P companies is taking a while to take shape. However, if market expectations for U.S. production levels continue to drop, that should have a positive impact on oil prices, which further supports consensus expectations for approximately 500 active rigs in the U.S. at year end. Taking this a step further, by our count, there are approximately 630 super spec rigs available in the U.S. market. Looking forward, we believe the vast majority of all working rigs drilling horizontal wells will continue to trend toward the super spec classification. And if activity does reach 500 rigs, the industry rig count would begin to approach utilization levels that have historically provided pricing power. Today, we are hopeful and encouraged by the recent worldwide deployment of COVID-19 vaccines. We're encouraged with an improving crude oil price picture, and we're encouraged by the progress we continue to make on strategic efforts to deploy additional digital technology solutions and to advance new commercial models. Even with the early success of vaccines for COVID-19, there remains a significant level of uncertainty regarding the global economic recovery as well as the changing political environment, and that certainly tempers our short-term optimism. While it's encouraging to see oil prices higher than expectations, we are cognizant that even in a stable or improving environment, there remain several challenges ahead for the industry. We are encouraged seeing the industry rig count begin to recover, but customers are still in the budgeting process to determine their capital allocation and those levels will set the tone for activity during the remainder of 2021. We do expect public E&Ps to maintain financial discipline related to their announced budgets. We also expect private E&Ps to add rigs. However, we don't expect an outsized increase in fiscal 21 rig count, even if oil prices reach $60 per barrel. A return-driven capital allocation strategy is in the best long-term interest of our industry, and that's what we're aiming to support with our solutions-based offering. H&P has a differentiated customer-centric approach of combining our people, rigs, and leading edge automation technology, which enables us to deliver the highest value wells for our customers. An underlying principle of our performance contracts is the creation of a sustainable win-win scenario based not only on efficiency, but also by employing the advantages of automation related to wellbore quality and placement. Our patented drilling automation software is a key driver in improving well economics for the customer by enabling the drilling of consistently higher quality and better placed well bores throughout the drilling program. To date, our autonomous auto slide technology is deployed on 25 to 30% of our flex rig fleet, and we currently have similar percentages for performance-based contracts. Automation solutions improve the drilling efficiency of the well, but it also has a significant influence on the lifetime value of the asset by delivering a better wellbore to the completion phase, which will ultimately enhance production economics. When successful, the combination of flex rig and digital technology solutions leads to superior well economics by lowering risk and increasing returns for our customers as well as for H&Ps. We can't control the macro challenges, but we can remain laser-focused on our technology solution deployment, our performance-based contracts, and our value accretion for customers. We're encouraged that several customers have adopted these new solutions, but we recognize that more work is ahead and additional efforts aimed at change management must occur within the industry. Accordingly, improvements in technology solutions and performance-based contract adoptions are not likely to be linear and may not always correlate with our rib count. That said, we're seeing remarkable progress that's being made today, and we're steadfast and confident in our ability to lead and effect change in our industry. I'm very pleased with our people's service attitudes. and the ability to quickly respond to customer demand and improve activity by roughly 35% during the first fiscal quarter. Our market share today is back to pre-pandemic levels. We are adding back more rigs in the competition due to our proven ability to reactivate rigs safely, efficiently, and cost-effectively. We believe there's an opportunity to grow our market share above 25%. If you look at previous downturns we have faced since the 2008 financial crisis, we have emerged stronger with greater capability as we differentiated our offerings and grew market share in the premium part of the market. Going forward, in a structurally smaller U.S. market, we believe super spec rigs combined with digital technology solutions that provide improved value through wellbore quality will prevail. Relative to the 800 rig drilling a year ago, many idle SCR and less capable AC rigs may be permanently sidelined. Further, not all of our competitors with SuperSpec rigs have the ability to enable the drilling automation features that many customers are beginning to require. In the SuperSpec classification segment, we have approximately 37% of the U.S. capacity with 234 super spec flex rigs that are unique with their digital technology capability across our uniform fleet. Another aspect of our asset deployment strategy we plan to execute will occur over the medium to long term in international markets. That strategy is to opportunistically reduce our US super spec concentration over time by deploying rigs internationally for appropriately scaled contracts. Our international business development team is seeing some bidding activity in Argentina, Colombia, the Middle East, as well as other markets. At this time, these prospects are in early stages, but we are encouraged by the customer interest in H&P FlexRigs due to a combination of our expertise in unconventional drilling, our strong historical performance in these areas, and the need for what we would consider an imminent legacy rig replacement, driven by an evolution toward digital technology for wellbore quality and placement. These are great opportunities for H&P in addition to our initiatives to improve our cost structure, where Mark will provide more details in his remarks. On the last call, we discussed having made investments in geothermal projects, and you may have seen some recent announcements by our strategic partners. Along with looking at emissions reducing opportunities like geothermal, H&P will continue to explore and invest in new and diversified technologies, as well as expand our digital technology capabilities for the long-term sustainability of the company. Before turning the call over to Mark, I want to underscore once more the focus and success our company has made on its strategic objectives, particularly given the economic and industry headwinds we are navigating. As we've indicated previously, introducing disruptive technologies and new business models is a long, arduous, and sometimes unpredictable process. I believe our dedicated teams are well-equipped, and our conservative financial stewardship on the challenges and opportunities ahead. And now I'll turn the call over to Mark Smith.
spk08: Thank you, John. Today, I will review our fiscal first quarter 2021 operating results, provide guidance for the second quarter, update full fiscal year 2021 guidance as appropriate, and comment on our financial position. Let me start with highlights for the recently completed first quarter, ended December 31, 2020. The company generated quarterly revenues of $246 million versus $208 million in the previous quarter. The quarterly increase in revenue was due to higher recount activity in North America Solutions as operators resumed some drilling activity. Total direct operating costs incurred were $200 million for the first quarter versus $164 million for the previous quarter. The sequential increase is attributable to the aforementioned additional rig count in the North America Solutions segment and the related rig recommissioning expenses. General and administrative expenses totaled $39 million for the first quarter, higher than our previous quarter due to the resumption of short-term incentive accruals for fiscal 2021, but within our guidance for full fiscal year 21. During the first quarter, we closed on the sale of an offshore platform rig to its long-standing customer as per a provision in the original long-term contract. The sale closed for consideration of $12 million paid out over two years. The rig had an aggregate net book value of $2.8 million, and the resulting gain of $9.2 million is reported as a part of sale of assets on our consolidated statement of operations. In connection with the sale, we entered into a long-term management contract for this rig in our Gulf of Mexico segment. Our Q1 effective tax rate was approximately 19%, which is on the lower end of our guided range due to a discrete tax expense. To summarize this quarter's results, H&P incurred a loss of 66 cents per diluted share versus a loss of 55 cents in the previous quarter. First quarter earnings per share were positively impacted by a net 16 cent gain per share of select items as highlighted in our press release. including the aforementioned offshore rig disposition. Absent these select items, adjusted diluted loss per share was 82 cents in the first fiscal quarter versus an adjusted 74 cent loss during the fourth fiscal quarter. Capital expenditures for the first quarter of fiscal 21 were 14 million, below our previous implied guidance. This is primarily due to the timing of spending, which has shifted to the remaining three quarters of the fiscal year. H&P consumed approximately $20 million in operating cash flow during the first quarter of 2021, in line with our expectations. I will have additional comments about our cash and working capital later in these prepared remarks. Turning to our three segments, beginning with the North America Solutions segment. We averaged 81 contracted rigs during the first quarter, up from an average of 65 rigs in fiscal Q4. I will note here that at the end of fiscal Q1, all idle but contracted rigs, which I will refer to as IBC rigs thereafter, had returned to work compared to an average of approximately 15 IBC rigs in the previous quarter. During the first quarter, we doubled our rig activity from the prior quarter low to 47 active rigs. We exited the first fiscal quarter with 94 contracted rigs. which was slightly above our guidance expectations as demand for RIGs continued to expand from the low reached midway through the end of the previous quarter. Revenues were sequentially higher by $53 million due to the previously mentioned activity increase. Included in this quarter's revenues were roughly $4 million of unexpected early termination revenue from the cancellation of one RIG contract. North America Solutions operating expenses increased $47 million sequentially in the first quarter, primarily due to adding 25 rigs, a 35% increase in North America activity, as well as reactivating 10 idle but contracted rigs, both of which resulting in one-time reactivation expenses of approximately $10.6 million. Looking ahead to the second quarter of fiscal 2021 for North America Solutions. As I mentioned earlier, we exited Q1 with slightly more rigs contracted and running than expected. The activity level has continued to grow, albeit at a more moderate pace than the prior quarter, as operators add rigs to maintain production levels with oil above $50 per barrel. As of today's call, we have 103 rigs contracted with no IBC rigs remaining. We expect to end the second fiscal quarter of 21 with between 105 and 110 contracted rigs. As John discussed, our performance contracts are gaining customer acceptance, and of the approximately 34 rigs that we have added to the active H&P rig count after September 30 through today, more than a quarter are working under such performance contracts. In the North America Solutions segment, we expect gross margins to range between $60 to $70 million with no early termination revenue expected. As we continue to add rigs, we will also incur related one-time reactivation expenses. Such expenses are expected to be approximately $6 million in the second quarter. As we have seen in previous cycles, there is a correlation between the reactivation cost per rig and the length of time a rig has been idle. As a reminder, most of our rigs were stacked back in April of 2020, nine months ago. Historical experience indicates that rigs stacked for nine months or longer will incur costs of $400,000 to $500,000 to reactivate. Reactivation costs are incurred in the quarter of startup, so the absence of such costs in future quarters is margin accrued. Our current revenue backlog from our North America Solutions fleet is roughly $448 million for rigs under term contract. But importantly, this figure does not include additional margin that H&P can earn if performance contract criteria are met. Regarding our international solutions segment, international solutions business activity declined from five active rigs at the end of the fourth fiscal quarter to four active rigs at December 31. This decrease is the result of an expected rig release in Abu Dhabi due in large part to the disruption created by the ongoing COVID-19 pandemic. As we look toward the second quarter of fiscal 21 for international, our activity in Bahrain is holding steady with three rigs working. We also have one rig under contract in Argentina. In the second quarter, we expect to have a loss of between one to three million, apart from any foreign exchange impacts, as the legacy structural costs in Argentina continue to hamper international margins. Also, we still have a pending rig deployment in Colombia that continues to be delayed as our customer waits on required regulatory approvals to begin work. Turning to our offshore Gulf of Mexico segment. We currently have four of our seven offshore platform rigs contracted. And we have active management contracts on three customer-owned rigs, one of which is on full active rate. Offshore generated a gross margin of $6 million during the quarter, which was at the lower end of our estimates. As we look toward the second quarter of fiscal 21 for the offshore segment, we expect that offshore will generate between $6 to $9 million of operating gross margins. Now let me look forward to the second fiscal quarter and update full fiscal year 2021 guidance as appropriate. Capital expenditures for the full fiscal 21 year are still expected to range between 85 to 105 million with remaining spend distributed over the last three fiscal quarters. Our expectations for general administrative expenses for the full fiscal 2021 year have not changed and remain at approximately 160 million. We also remain comfortable with the 19 to 24% range for estimated annual effective tax rate and do not anticipate incurring any significant cash tax in fiscal 2021. The difference in effective tax versus statutory rate is related to permanent book to tax differences as well as state and foreign income taxes. Now looking at our financial position. Humber Campaign had cash and short-term investments of approximately $524 million at December 31, 2020 versus $577 million at September 30, including our revolving credit facility availability. Our liquidity was approximately $1.3 billion. Not included in the previously mentioned cash balance is approximately $35 million of income taxes receivable in related interest that we collected after the end of the first fiscal quarter. Our debt to capital at quarter end was about 13%, and our net cash position exceeds our outstanding bond. H&P's debt metrics continue to be a best-in-class measurement amongst our peer group that allows us to keep our focus on maximizing our long-term position. As a reminder, we have no debt maturing until 2025, and our credit rating remains investment grade. Now a couple of notes on working capital. Our trade accounts received will at fiscal year end of 150 million grew by 38 million to approximately 188 due to the added rig activity as previously mentioned. The preponderance of our AR continues to be less than 60 days outstanding from billing date. Also included in AR is another approximately 10 million of tax refund receivables. Our inventory balances have declined approximately 5 million sequentially from June from September 30 to 99 million, and we continue to leverage consumables across the entirety of U.S. basins to use and reduce inventory on hand. These efforts are resulting in better spending rationalizations that are reducing our out-of-pocket expenditures. Our accounts payable terms optimization project mentioned on the last ratings call will extend our payable terms with certain key vendors. And finally of note are, one, The majority of our annual ad valorem taxes accrued through the year are paid annually in the fourth calendar quarter. And two, the short-term incentive compensation accruing for fiscal year 21 will not be paid until the first quarter of fiscal year 22. As I mentioned on the November call, we expected to use a modest amount of cash on hand as we worked toward a 100-plus rig count activity level. As mentioned earlier in my comments, we arrived at a 100 rate count level during this second quarter. We believe at this activity level, our point forward quarterly operating earnings will fund our maintenance capital expenditures, debt service costs, and dividends. Based on our updated forecast, we expect to end fiscal 2021 with cash and short-term investments at or above $500 million. In closing, we are continuously working to manage our costs, both operating and SG&A expenses, as well as capital expenditures. We believe active cost management is crucial in the now structurally smaller United States upstream market. Various initiatives are underway to identify and drive out costs where possible to enhance margins going forward. That concludes our prepared comments for the first fiscal quarter. Let me now turn the call over to Christy for questions.
spk03: At this time, if you would like to ask a question, please press the star and one on your touchtone phone. You may remove yourself from the queue at any time by pressing the pound key. Once again, that is star and one to ask a question. And we will take our first question from Tommy Maul with Stevens. Tommy, go ahead, you're line up.
spk11: Good morning, and thanks for taking my questions. Good morning, Tommy. John, I wanted to start on performance-based contracts for as long as you've been talking about that initiative, you've been very clear that it's not a change in the industry structure that's going to happen overnight and that it's going to take some time. What context could you give us about how the downturn may have accelerated customer willingness to talk about new types of pricing models versus made it more difficult just given how stretched a lot of customers were. Maybe it was just not something that they were willing to engage in conversations with.
spk02: Sure, Tommy. Good morning. You know, it's really – you won't be surprised by this – it's really a mix. You know, every customer – at this stage of the game, probably views it a little bit differently. I think there are some, as a result of the downturn, as you mentioned, I think it has accelerated their thinking. They recognize, as much as we do, that the industry really has to evolve. And so customer adoption of these new models are, you know, it's different across the board. I think what we're encouraged by, though, is that There are, as we said in our remarks, 25% to 30% of our rigs are under performance contracts or some new commercial type. And I think the reason is by definition it's that performance-based contract. It's a win-win opportunity when you execute it properly. And it really delivers a higher level of value for the customer and at the end of the day for H&P as well. We have continued to stress that in order to be truly successful, it really has to be a partnership agreement with your customer. There's got to be mutual trust. There's got to be mutual respect. I think there also has to be an acknowledgement that we each have strengths and there's areas that we can leverage those strengths for the betterment of the project. Taking it really, and this is where I think it's most valuable, and it really relates to our decision to have an approach more focused on solutions, overall solutions. Because we're combining our digital technology solutions. AutoSlide is the easiest one to talk about right now. But we're taking a focus, and it's not that we're not still interested in taking a 20-day well to 15 days or a 15-day well to 10 days. We want to do that, but we're also focusing on the lifetime value of the asset. Our customers are doing that, but we haven't necessarily been engaged in that discussion. As you think about wellbore quality and wellbore placement and the things that we're doing, we're really focusing on the lifetime value of that wellbore for the next 10 or 15 years. I think that is really drawing some attention. Again, we're seeing some opportunities to continue to grow these new models with our customers. As you can imagine, the day rate, it's really hard. Our teams are doing a great job. They're out there selling the benefits, and I think we're starting to see some results.
spk11: Thank you, John. That's all very helpful. As a follow-up, I just wanted to move to the topic of overall industry rig count. I want to ask you to make a specific call on a number, but maybe just give us a sense of what the contour might look like based on your customer conversations. Does it seem like decision-making among customers has maybe been delayed a little bit? In other words, maybe in a typical year there would be better visibility into a full-year drilling plan. at a rough timeframe in your mind versus this year, it just seems like there's a lot more uncertainty and that you may end up getting a better peek into what those plans look like later into this fiscal year than normal? Or do you feel like, based on your conversations, you have a pretty good sense of what your customer base will be doing to calibrate for the full-year drill plans?
spk02: There's no doubt that the market, obviously, once customers decided to put rigs back to work, it moved very quickly. As we've said in our remarks, we're pleased to be at 103 rigs today. I think our low was 46 rigs, low active rigs, 46 rigs in December. We still have this quarter ahead. We're at 103. We set a range of 105 to 110. Our goal is to hit 110. Team's working hard. We want to make certain we do that. But it is very hard to see, and you've heard me say this over time for a long time, really, regardless of the market. It's hard to see much past three months. And so we do have some insight into April and May. But as you know, the budgets for the public E&Ps, they're not all final. I think when you start thinking about a ramp in activity, we shouldn't expect a ramp like we've seen since August. I think it's going to be a much lower increase. The other really surprise to everybody is that oil VTI is as high as it is. It wasn't that long ago. We were talking about 45 to hopefully getting to $50. You know, one of the ways that we've tried to think about it, again, and thank you for not asking me to predict rig count, but if we have the opportunity, and we do, we look at the sell-side consensus and you look at, you know, there are estimates out there of having 500 rigs running by the end of the calendar year. And I think that's possible. And if you think about it, that's not a long way from where we are today, and you don't have to add a whole lot of rigs over the next 11 months to get there. I think clearly our customers are going to remain disciplined. What they're doing is in the best interest of their companies and the best interest of our industry, I believe. We're going to see how that plays out. We talked about the need to have a return-driven capital allocation strategy. We think that's in the best interest of the long-term outlook for the industry. So hopefully that answered your question. I wish I could nail a number. I do think the rig count will continue to increase, but I do believe it'll be at a much slower pace than what we've experienced over the last four or five months.
spk11: Fair enough. Thank you, John. I'll turn it back. Thanks, Tommy.
spk03: And we will take our next question from Ian McPherson with Simmons. Ian, go ahead.
spk00: Yeah, thanks. Good morning, John and Mark and Dave. The thing that stood out to me initially was the improvement that you've gotten for your North America cash margins for the segment profit, you know, divided by rig count for this quarter and even backing out determination and reactivation expenses, which I think net out to kind of a wash quarter to quarter. It's a healthy improvement. This has been a big sort of debate point for you and peers as to where cash margins might ultimately trough out. And so, John, just given your constructive framework that you see for tighter super spec utilization by the end of this year and maybe some pricing power stabilizing or maybe improving the low spot rates that we've seen and heard about, Does that give you more confidence than maybe you had last quarter with regard to, you know, having some visibility now to a true troughing in your cash margins? And is that going to look somewhere close to what we see here with the second quarter guidance for margins?
spk02: Well, I'm going to direct Mark towards the details, but I do think we are working hard. I mentioned earlier we're working hard to retire the day rate, and we obviously have rigs that are rolling off of term contract. That works somewhat against us, but we're also working with customers to enter those rigs into performance-based pricing, and so that's beneficial. I do think that we're seeing some uptake on that, which hopefully, again, helps us on the revenue side of the equation and ultimately generating better margins.
spk08: Mark, what would you add? Thanks, John. Several things to think about in there. Certainly this quarter we just exited, we had some pressure, obviously, from the recommissioning expenses. Another thing we had a little bit of upward pressure on as well was you may have heard me talk about quote unquote penny stock over the prior couple of quarters in the last calendar year. We've kind of gotten through that penny stock as we increased activity and as a consequence we've begun really digging into our on hand average cost of inventory which drives up M&S costs. There's just other things in there that are moving around, not necessarily all linear, but increasing activity levels has a positive impact, obviously, on our fixed cost leverage. I think your comment on troughing out maybe potentially because we had gotten down to that 47-rig low point of activity last quarter, I mean the previous quarter, so we're getting more activity. leverage there with this increased number of rigs you know we're still going to have reactivation expenses coming through obviously we we have a roll-off on the revenue side of some term contracts but you know obviously helping that are the performance contracts that we are putting in place so again not all linear a lot of moving parts I think that You know, in addition to all of that, as I mentioned, we're working on a lot of cost out initiatives as I'll term it. I'm not going to go into a lot of details on those. But over the next couple of quarters, we hope that those are, you know, additive and each of the initiatives and the aggregate helps take some cost out of the system. And then I guess just, you know, as I'm thinking out loud here, finally, there's a little bit of apples and oranges as we move through this last year. and took what were two segments, legacy U.S. land and HPT, and combined them into North America Solutions, you pulled in some of that overhead cost from the legacy HPT, so there's a little bit of increasing cost there. So a lot of moving parts. Ian, is that helpful?
spk00: Very helpful, and at the end of the day, look, we have your cash flow outlook for the year, which kind of pulls it together for us as well. That's good. Thanks. I wanted to ask a follow-up, though, on the international side. You know, we've seen Argentina and Colombia, they went from 100-plus rigs to zero last year, but they're racing upward back to probably 50-plus today. So... wanted to get, John, your thoughts on how you can or how you want to and aspire to participate in the continued recovery there in those historically very strategic markets for you internationally.
spk02: Yes, Ian. I mean, we've been in both countries, Argentina and Colombia, for a very long time. And we have a great personnel base, great people and country. great asset base in both countries. And so, yeah, I think we're going to participate in that. I mean, there's no doubt that we'll see some rigs going back to work in both countries, but there are things that are challenging that are not just the macro side. There's other challenges that we have. We're definitely interested. I think we have a great opportunity to put rigs back to work.
spk08: Mark, what would you What would you add? Just a couple of other comments, Ian. You know, some of those initial rigs, I think, as we might have mentioned on a previous quarter call, were some workover work. And then also the equivalent of the contracted rigs as we had in the U.S. going back to work that were parked for some operators. You know, as John said in his prepared remarks, we are seeing, you know, bidding and tendering activity in-country currently. And, you know, the SuperSpec rig that we had sent, goodness, was it 18 months ago now, down to Argentina, some of those conversations we're in with folks are about the SuperSpec capability. Again, as John alluded to about our kind of mid- to long-term international look, we really think that the SuperSpec rig there and potentially upgrading other rigs there through time can really be beneficial to that market.
spk02: I think the international market in general, just to add on a little bit more color, in the U.S. we've been undergoing this replacement cycle for well over 15 years. There are many, many countries that have still very old assets, SCR, even some that are newer versions. When you really look at it, particularly if you're going to be drilling a horizontal, unconventional well, they're not ideally suited for that type of work. I think that's why it puts us in a great position to grow internationally. We obviously have the capacity to move flex rigs out of the US. We've obviously done that in both countries we were talking about as well as the Middle East. We just need to get more scale. We think the opportunities are there and I think you know, with a slowdown in activity that we've seen internationally, we're going to see some pickup. There's usually, you know, six months, nine months delay in getting the international count back up.
spk09: Got it. Great. Thanks, John. Thanks, Mark. Thanks, Ian.
spk03: And we will take our next question from Sean Mecham with J.P. Morgan. Your line is open.
spk06: Thank you. Hey, good morning. Morning, Sean. So I'd like to maybe just talk a little bit more about how the market share in the rate count has been unfolding. What do you think it means for your opportunities going forward? So at current levels, the data suggests the five largest land drillers have only maybe 60% market share today. So smaller drillers seem to have an outsized share relative to their share of super spec supply. So would it be your stipulation that those small drillers have their super spec or their best approximations of super spec rigs probably mostly utilized at this point, and the incremental capacity to be soaked up will be predominantly among the large drillers led by yourself?
spk02: Well, Sean, you know, I don't recall seeing that as a data point. Dave or Mark may have some additional color on this. What I will say is You know, if you look at the, and let's face it, most of the rigs that went back to work or a large portion of the rigs went back to work were in the Permian. And I think of the rigs that went back to work in the Permian, we captured two-thirds of that share. So I'm a little surprised that it's at 60%. I think the five largest drillers owned about 80% of the super spec capacity. And I'm not certain how that, how that looked in terms of rigs that have gone back to work. I do think there's much more to the story than just the classification of the rig because what we're seeing is, again, more of a manufacturing-type approach. If you really are looking at the premium end of the market, you think about our business, and it's amazing the efficiencies that we've been able to drive in our industry. But when you start getting to the efficiencies that we're at now, in order to get to that next level, you really need some automated solutions. We're still relying heavily on human decision-making, and that decision-making is a 24-7 decision-making process. So there's obviously opportunities to do better with software. And so I think the smaller companies are going to be challenged even more, not only on the rig spec side of the equation, but on that digital side of the equation. So, Dave, did you have time to look at your notes? Do you have any follow-up on that or mine?
spk04: Yeah, I just follow up on over time, you know, these smaller players don't have the – the technology that some of the larger players have and that there's going to be a differentiation even among the super spec rigs over time. And so I do think the larger players that have that technology are able to provide that value are going to get, get the lion's share of the rigs.
spk06: I appreciate that. I think part of what I was trying to get at is to the extent that, you know, they've got their best rigs running at this point. You know, they tend to have small numbers, right? Single digit numbers of these types of rigs that, the larger drillers remaining with the remaining capacity, that would probably help your confidence around pricing progression that you'd have, considering who'd be likely to bid on future opportunities. Yeah, sure.
spk02: I think that's right. I think you're making a great point there on this. Yeah, so I apologize.
spk06: I was kind of closing the loop late on that question. So then the other thing I was thinking about was with respect to private EMPs, They've been a bit of a swing in demand, coming back quicker. That's consistent with historical trends. And they potentially can be more of a swing later in the year if oil prices hold and they have some incremental cash flow. So, John, what are you seeing in terms of their uptake for super spec and incremental automation and software solutions? Is it too early or can we get a bit of a read on appetite for that part of your portfolio versus maybe where those types of operators would view them, say, pre-2020?
spk02: I tell you, I've been very pleased with the response from the private companies, private equity companies, small privates, just in general. We have some very strong partnerships, and in a couple of cases, we've whether they're two rigs, three rigs, or five rigs. We've got all of their rigs. They're all in on the FlexRig. They're all in on the digital solutions. They're partners with us. We've got some, as an example, in alpha and beta testing, we've got auto geo-steering, and one of the private companies are working with us on that. So that's encouraging to see. You know, the question earlier about the downturn, let's face it, downturns, that's a time for survival. And so we're all trying to figure out how can we make our businesses better and more durable. And so we're seeing that. Again, fortunately for H&P, it's not just on the small private side, private equity side as well. We're also seeing it, of course, with our larger companies. publicly traded companies as well as supermajors. So we've been very pleased with the response.
spk10: I appreciate that. Thanks, John. Thank you.
spk03: And we will take our next question from Taylor Zurcher with Tudor Pickering Holt. Your line is open.
spk07: Hey, thanks and good morning. We've talked a lot about the continued adoption of these performance-based models and clearly some of these software solutions you're offering are a big piece of the value added there. I wanted to touch on the hardware side of things. You've got, off the top of my head, I think somewhere in the 40s in terms of walk-in rigs in your fleet. If we look at the 30-ish percent of your fleet that's under performance-based contracts today, is a big concentration of that with your walking rigs and, and, um, you know, do you have a target moving forward or do you need to, to, to increase the number of walking rigs to, to also increase notably that the performance based percentage of your contracts or those two, uh, kind of independent factors moving forward?
spk02: That's really, it's really independent, uh, factor. Um, We do still have some conversions in process on the walking side of the equation. But we've been very fortunate, whether it's walking, whether it's Flex 3 skid or Flex 5, we've got really kind of across the board customers have those rigs that really suit their well designs and the paths that they're building. So there's really not any push towards one or the other on the performance side.
spk07: Okay, and with a number of quarters of some of these performance-based models now in the books, are you seeing any customers sort of accelerate the timeline where you re-look at the underlying KPIs in these contracts or Is that sort of still an evolving process right now?
spk02: You know, it's really evolving. I know there's continued, it seems like, concern and angst over kind of resetting the bar. And I think it kind of goes back to my earlier comments related to building strong partnerships and having mutual trust and recognizing and acknowledging the strength that each brings to the party. At the end of the day, if we're able to deliver better performance than they can working with brand X, Y, or Z, then that's great for them and it's great for us. We really haven't seen that much. Again, we recognize it as being a risk, but at this stage of the game, we're not overly concerned.
spk08: Mark, did you have something you wanted to Yeah, just I would add, John, that, you know, for some of those customers who've been with us on the journey longer and are early adopters of the performance contract, they've seen the full effect of the use of the technology and the improvement on the wellbore quality along the way. So what that does is that enables us to go to a completely different set of goalposts over time, Taylor, and that is looking at quality of the well. So if you think about, you know, the overall spread cost to build a well, you think of the pie shape. You know, we're a slice of pie for our drilling costs. Completions are half a pie. And if a less tortuous well bore can be completed and fracked more easily and reduce the cost of that part, well, that's a certain total cost of ownership benefit for our customer that we can participate in. So we're working with some customers on defining things, such things as tortuosity index, and trying to move to a different set of goalposts and get off of the – get off of the efficiency treadmill.
spk07: Got it. That makes sense. Thanks for the answers.
spk09: Thank you.
spk04: Chris? Do we have any more in the queue?
spk03: Yes, we have Wakarth Syed. Your line is open.
spk01: Okay. Thanks for taking my question. A couple of things. First of all, are you seeing any input cost inflation, whether in trucking or for steel, a drill pipe or anything like that?
spk08: Wakarth, good morning. No, not yet. Now, obviously, steel prices have increased this last year, as we know, but we have a lot of extra componentry in our system from spares and from our previous ramp-up and rig activity before this downturn that we've discussed previously. So, we haven't had to buy anything new to deal with the increased steel costs. Having said that, I definitely see through time, I think this will hit us probably more in fiscal 22, that when we get to the next round of tubular replacements, that certainly could come into play. But through the rest of the system, no, we haven't seen any inflationary pressures. Good, good.
spk01: And then just my last question in terms of, you mentioned a number of tenders on the international market right now. When are right now, you know, what are they telling you in terms of when this contracts would, you know, actually start up, fully recognizing that international things keep, you know, tend to get pushed to the right?
spk08: Well, as John said in his prepared remarks, we do see that tendering activity in its early days. But just to your point in John's comment, there's no certainty on that stuff now because Some of these tenders we bid on, actually, when the bid date comes and everything's finished, then guess what? The date gets pushed to the right and you re-bid it again. But the good news is that that potential deal flow is coming through, whereas this time last year it was not. So that's an improvement in the right direction. I think as we get more certainty around the vaccine rollout and the next post-pandemic hopefully, COVID world, that we should see that open up a bit more when demand is more fulsome.
spk01: So just like for the second half calendar year, 2021, do you think you'll have more incremental rigs active in LATAM or in Middle East or same for both?
spk03: Okay, get it off.
spk02: Well, Carr, we're sure hopeful. What is it? There's so many things that, as we've said, there's still uncertainty out there. Things are definitely looking better, and with the lag time that we generally see with international, I think your timing is spot on. We just hope that things keep moving the direction that they are, and hopefully we're able to close on some of the deals that we think we can close on.
spk01: Thank you very much.
spk02: Thanks, McCarr.
spk03: And we will take our next question from Scott Gruber with Citigroup. Scott, your line is open.
spk09: Okay, Scott.
spk10: We can't hear you, Scott, if you're on there.
spk05: Are you able to hear me now?
spk10: Yeah.
spk05: I'm sorry about that. Morning. Mark, are you able to say the performance contracts and the bonuses that you receive under them, how much did that benefit fiscal 1Q margin? And more importantly, assuming a similar achievement rate going forward, Does the performance bonus potential improve in the quarters ahead on a per day basis? And if so, any color and how much?
spk08: We haven't really quantified that publicly, historically. But I'll tell you, just anecdotally, if you look at some of the term contract rollovers we've had, And so basically going back in time a year to previous spot rates. Spot rates in the market are obviously lower today, but what these performance kickers allow us to do is really kind of bring that, is bridge that gap, if you will, between the two. So that's been, it's certainly been margin accretive to us and equally beneficial to our customers' costs as well.
spk05: Gotcha. But any comment on whether that kind of opportunity, you're putting more contracts in place, but I guess is the margin benefit from them improving going forward or kind of static at this point?
spk08: It's a customer-by-customer relationship by specific customer need basis. So if you look at these performance contracts we have in the portfolio, there's no pure linear derivation that can be had with them, I think. It's really, you know, as John's been talking about, it's the solutions-based approach. And so each set of KPIs is different for each unique customer and the pad they're on and the things that they need to accomplish.
spk05: Got it. That was it for me. Appreciate the call, Mark.
spk09: Thank you.
spk05: Thank you.
spk03: This does conclude our question and answer session for today. I will now turn the program back over to our presenters for any additional or closing remarks.
spk02: Thank you, Christy, and thanks again to all of you for joining us today. As we have touched on during this call, there are many challenges ahead. However, we believe H&P is in a strong position to take advantage of these opportunities. we recognize that the only sustainable way forward is for our industry to continue to evolve. And we are approaching that change with our customer-centric approach, which includes digital technology, performance solutions, and an equitable sharing of created value. So thank you again for joining us today.
spk09: Have a great day.
spk03: This does conclude today's program. We appreciate your participation. You may disconnect at any time.
Disclaimer