Helmerich & Payne, Inc. (HP) on Q2 2021 Results - Earnings Call Transcript
Operator: Good day, everyone, and welcome to the Helmerich & Payne Fiscal Second Quarter Earnings conference call Please note, this call is being recorded. It is now my pleasure to turn the call over to Vice President of Investor Relations, Mr. Dave Wilson. Please go ahead, sir.
Dave Wilson: Thank you, Jim, and welcome, everyone, to Helmerich & Payne conference call and webcast for the second quarter of fiscal year 2021. With us today are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us, after which we'll open the call for questions. Before we begin our prepared remarks, we'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based on current information and management's expectations as of this date, and are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements. We will also be making certain references to non-GAAP financial measures, such as segment operating income and operating statistics. You'll find the GAAP reconciliation comments and calculations in yesterday's press release.
John Lindsay: Thank you, Dave, and good morning, everyone. Reflecting on where we were at this point last year, I'm encouraged by the recovery we are currently experiencing as well as how the company has navigated through a multitude of challenges in 2020. Last year, I said that two factors were crucial for our continued success going forward. First, maintaining our financial strength and second, maintaining a long term focus for future opportunities. I'm happy to report that the company continues to execute in both areas. Today's mid $60 oil price is robust compared to what we experienced over the past year. But going forward, we anticipate a degree of permanence in the change of historic industry behaviors and norms. Energy markets are coming back into balance, global oil demand is reviving and oil inventories are falling back to their five year average. The energy industry's capital discipline, which actually began prior to the global pandemic, also remains resolute. While this last point is uncomfortably limiting for the industry's near term growth horizon, this is something we believe is imperative; focused disciplined spending that generates returns under a variety of commodity price scenario is what the industry needs to attract and retain investors. Back to the long term focus and what we believe the future holds for H&P. A natural step and capital discipline is driving the most value per capital dollar spent, not just in a one year budget cycle but over the life of an investment. This corresponds to where we believe H&P as the leading drilling solutions provider contributes the most value to our customers and is the driver behind the development of our digital technology solutions and our new commercial models that are structured around achieving value added outcomes. Aligned with our strategic objectives, H&P will continue to concentrate on delivering value to the customer by leveraging software, data and FlexRig technology. Our digitally enabled drilling operations provide automation solutions that deliver both efficiency gains and wellbore quality. Not only do our customers experience near term financial benefits like lower well costs and the reduction of certain downhole risks, but also improvements in areas that were historically beyond our ability to influence, but have significant economic implications over the long term life of the well. An important ingredient to a successful technology strategy is the integration of new commercial models, which incorporate performance metrics and eventually wellbore quality metrics. One example is having a tortuosity index and tying them together with financial remuneration. New commercial models are designed to generate win-win outcomes. The customer has a well with improved economics, and H&P is compensated for helping to create a portion of that value. Currently, approximately 30% of our active US fleet is under some type of performance contract. Contrasting the successful adoption of these new commercial models compared to a year ago where we only had about 10% of our fleet on performance contracts. Our digital technology is providing H&P and our customers another differentiating capability and delivering the best outcomes.
Mark Smith: Thanks, John. Today, I will review our fiscal second quarter 2021 operating results, provide guidance for the third quarter, update remaining full fiscal year 2021 guidance as appropriate and comment on our financial position. Let me start with highlights for the recently completed second quarter ended March 31, 2021. The company generated quarterly revenues of $296 million versus $246 million in the previous quarter. The quarterly increase in revenue was due to higher rig count activity in North America Solutions as expected. Total direct operating costs incurred were $231 million for the second quarter versus $200 million for the previous quarter. The sequential increase is again attributable to the aforementioned additional rig count in the North America Solutions segment.
Operator: We'll take our first question today from in Ian MacPherson at Simmons.
Ian MacPherson: So it sounds like you provided us with the building blocks to confirm what we were expecting with respect to margins improving beyond your fiscal third because reactivation costs going forward as a percentage of the total pie should be easing. Spot pricing has bottomed. And you'll have probably increasing share of performance contracts that are probably accretive to your margin as well. So I wanted to confirm that directional bias for margins to probably begin to tilt upward a little bit after the third quarter unless the state of the world changes? That's my first question.
John Lindsay: I think you're right on that. We do feel like rates in general are off of the bottom and we've been able to see some improving pricing and as you said, improving commercial based or performance based type contracts. So yes, we think we're working on increasing that. And I think just in general, the super spec fleet, while not at near 80% utilization, I think when you look at what is available and idle, it's been idle for quite some time. And I think that ultimately drives some higher pricing as well as we continue to activate rigs.
Ian MacPherson: And John, as you go about this sort of maintenance scrapping program. How much idle capacity of super spec rigs is makes sense for you to keep in the back pocket? How much idle capacity do you think you need for the cycle ahead?
John Lindsay: Well, Ian, I'll let Mark give some additional color and details on that. But we haven't scrapped anything that's of super spec capacity. Everything that we scrapped is lower tier FlexRig 4 and older Flex 3.
Mark Smith: Yes, Ian, just to footnote that. Everything that we are calling from the fleet, as I mentioned in the prepared remarks, has really been previously impaired to some sort of salvage value, but also along the way, these rigs, calling them rigs is really kind of generous. They've been utilized as donors for equipment and components, they're not a complete rig, if you will. They're really mainly Flex 4 rigs and non super pec rigs that we impaired going back to June of '19 and March of last year.
Ian MacPherson: So if we just subtract your working rig count now to where you were at the peak a year ago, is that a good proxy for what you are less than $1 million reactivations reserve looks like?
Mark Smith: Yes. I think, Ian, I think that's a good approximation.
Operator: Our next question will come from Taylor Zurcher at Tudor, Pickering and Holt.
Taylor Zurcher: The first question I have is really a two part question as it relates to some of the moving pieces for the June quarter. So reactivation costs, obviously, a bit elevated as you're putting a whole bunch of rigs back to work. I just wanted to clarify, are you able to pass through any of those costs to the customer today? And then secondarily, you talked about a number of term contracts, which are rolling over in the June quarter. I suspect most of those are under the traditional day rate model. So I was hoping you could help us understand if you expect any of those rollovers to transition to more of the performance based model as we prepare us forward?
John Lindsay: Taylor, I think it's going to be a mix. You won't be surprised by that. I think there are definitely rigs. Our customers that we're partnering with today on performance based contracts that have rigs that will be rolling off and they will, I believe, be interested in pursuing a performance based contract again because it's a win-win opportunity for them and for us. There will be some more than likely that we'll just roll into a day rate type contract, which will be lower than what the leading edge pricing was then. But again, I expect them to be at improved pricing from where you might see the average today or definitely off of the bottom on what we experienced. On the reactivation cost, again, that's a mix as well. I mean, historically speaking, we're not going to put a rig to work for one well. We're not going to reactivate a rig that's been idle for six, nine, 12 months for the expectation of only drilling a well. We're typically going in with some sort of a term or some sort of a commitment, or some sort of a way to get paid back over time that reactivation cost. And of course, they're all different. This is not unusual. If you just think about market cycles over the past five, eight years, 10 years even with the cycles that we've had where you reach a certain part in the cycle where the market is tight enough that you're able to start passing more of the cost over to the customer, which, again, makes sense as the market tightens. Hopefully, that helps.
Taylor Zurcher: And my follow-up unrelated and more as it relates to capital allocation moving forward. The cash balance is obviously still very healthy. The dividend is a top priority, but you can cover that pretty easily moving forward. And so I was wondering if you could help us think about how we should view M&A for H&P moving forward, particularly on the technology side, I suspect that's still going to be the focus. But are there any kind of notable gaps that you'd like to fill in on the software, digital, et cetera, side moving forward that you might do inorganically versus organically, or maybe it will be a mix of both? So any color there would be helpful.
John Lindsay: On the M&A side, on the rig side, that's not something of interest. We've always got our eyes open on the technology side. I mean we've made some, what I think are some very strong acquisitions over the last four years, coming up on four years. And there's not anything right now that comes to mind, but I'll say that we're obviously looking to be opportunistic. And if something comes up, we're definitely going to look at that. But I think right now, I feel pretty good about where we are. Mark, do you have anything you want to…
Mark Smith: Yes. I would just add that maybe in as we consider capital allocation Taylor beyond, M&A, we'll look at -- for the international expansion, John discussed in his prepared remarks, we'll look at opportunistic growth opportunities, including organic ones for the Middle East, by way of example. But when speaking of capital allocation, it's for us, in particular, it's returned to shareholders, our long history of the dividend. And something that we consider as we move forward, potential dividend accretion, special dividends as others in the energy complex have done and share buybacks as we have our $4 million per annum authorized share buyback program that we can get into. But yes, these are the things that we're talking about at Helmerich campaign.
Operator: Tommy Moll at Stephens.
Tommy Moll: John, I wanted to start on your progress with new commercial model and drilling, automation, penetration, all those metrics are up and to the right, which is great to see. I'm curious at the customer level, have you had any customers that maybe tried a new commercial model on a handful of rigs and then scaled the approach across their entire program? In other words, a customer that's tried it and then leaned in fully. Or do you find that you're driving those penetration numbers higher as more -- a larger number of customers trying out the new models on a rig or two? And where I'm going with this, is I'm just trying to think about a potential tipping point there and what the pathway might be going forward? I know it won't happen as quickly as we'd all hope, but I'm just trying to think about the building blocks.
John Lindsay: Your first example, it's both. We do have customers that started with one rig, two rig. And now they've got it on every rig that we have working for them in the fleet. Same way with the technology offerings, AutoSlide automation and those solutions same way they start with one rig and then they continue to grow. But we've also had new customer, or customers adopt it new. So we do have additional adoption. We're seeing additional opportunities to partner on drilling automation and the new commercial models. At times, I liken this to the early days of the FlexRig, as you can imagine, not every customer was looking for an advanced technology rig and particularly one that was a much higher price than what the going rate would have been for a conventional rig. But thankfully, we had the early adopters were able to partner with, they saw the benefits, and we created a whole lot of value. So now we're taking this very old commercial model with the traditional day rate, and we're having to approach it in a different way. So we're learning as an organization, our sales force and our account managers, our marketing group, our operations folks, everybody is working together as a team with the customer to make this happen. So I really think that we're going to continue to grow that capability. I'm pleased to share, like I said in our prepared remarks that 30% of our working fleet today have commercial models and a year ago, it was 10%. So we're continuing to grow in that respect. Another great point to make is AutoSlide retention, we've seen 100% retention over these last -- I don't even know how long it's been. We have over 30 jobs running. It's another example where we have customers that start with one rig, and then they're up to four rigs, or up to six rigs, and then we have new customers that are coming in and adopting the technology. Again, when you start thinking about the advantages to the customer, the advantages with AutoSlide and automation is it's not just in the drilling of the well. We're leaving behind a better well, higher quality wellbore. We have advantages while drilling the well, like I'd mentioned, extended downhole tool life, smoother casing runs, increased reliability, reduced time on the well. But we're also delivering a less tortuous wellbore, which also has an impact on the completion side of the equation and really the lifetime value of the well. So we're really encouraged that we're seeing additional adoption. Again, as I said on the last call, it is a partnership. We both have strengths that we bring to the party and we're having to kind of expand outside of our normal area that we've worked for the customer. So overall, I think it's moving along pretty well.
Tommy Moll: And you mentioned wellbore quality there, which is something that I wanted to follow up on. So I believe in your prepared remarks, you indicated that incorporating some terms related to wellbore quality is either in the early stages or maybe we're not there yet in terms of the new contract structure. But just conceptually, on that point, how do you approach it with one of these more performance based models? I think it's a newer theme for us to think through. And so I'm curious what that concept looks like.
John Lindsay: I think the two examples. One is what I had in my prepared remarks and I think we may have talked about this on a previous call, but we've had several customers recognize that when drilling the curve by using automation compared to using a human, doing the decision making of drilling that curve we're actually able to land that curve, 150 to 200 feet earlier in the zone. And it creates an additional frac stage. Well, there's obviously risks in doing that and what customers have seen is that it's more challenging for a human directional driller to do that. And so that's an example of delivering additional wellbore, a better curve. The tortuosity index, we have a tortuosity index, and we've developed that. We have other customers that are developing it. And I think that's something that ultimately will be used more in the future right now. I think it's still really early stages. The good news is that we're finding additional advantages as we go through this process. No surprising as you start thinking about leveraging these technologies. So there's more to come on that but I do think there will be more metrics that we can share and talk about in the future.
Operator: Our next question today comes from Waqar Syed at ATB Capital Markets.
Waqar Syed: John, a couple of questions here. First of all, as I look at some of the information provided in the press release, I think that you've added maybe 10 to 15 rigs under kind of long term contracts like 18 to 24 months out. And one, is that correct? And if that's so, what do you think -- what are the rates on those, the base rates? Are they substantially above where the current spot is or they are being locked at the spot rate with the performance based contracts to provide upside.
Mark Smith: We had a few, as you see in the press release, term contracts resigned and those prices are above what the spot market is. So we're happy to see that.
Waqar Syed: And then secondly, historically, you mentioned the performance based contracts kind of add around $1,500 per day or so to margins. As you've collected the data over the last six, eight months, are the numbers coming in, in line with those expectations or exceeding those expectations, or how do you frame the reserves so far?
Mark Smith: Waqar, this is Mark. It depends on the customer, the rig, the region, but we're still in between 1,000 and 2,000, yes. And that same ZIP code, if you will, on the incremental uplift for the performance contracts.
John Lindsay: And I think the thing that to -- and it's one of those things that in working with our customers, again, we're working on delivering outcomes. And obviously, whether it's $1,500 or $2,500 on a per day basis, the outcomes we're delivering were -- that additional revenue more than pays for that additional value add. So that's the opportunity set Waqar is. And then as we do a better job of that, we do more of that. And the reality is, I don't think there's others out there in our peer set that are able to deliver that same level of performance we're talking about. So that's the opportunity set.
Waqar Syed: And then just finally, like normally in international contracts, you have six to eight months kind of lead time before the rig starts to turn to the right. So from our modeling perspective, for the next, like, through calendar, end of calender '21, should we not model any incremental rigs beyond the four to six that you've mentioned?
John Lindsay: I think all week and really -- and you've heard me say this for years Waqar, it's really hard to see with certainty much past a quarter. We're working really hard to hit those targets, like we did the last quarter, we're going to hit that 120 to 125 target. Obviously, we're pushing for 125. I do think we're going to continue to see a slight increase in rig count during the remainder of 2021. Obviously, a lot of that is a function of oil prices. We do think our customers are going to maintain discipline. And they're going to spend within their budgets, I think particularly on the public companies. So I think that's going to be the case. However, as we begin to set up for the back half of '21 and getting ready for '22, if oil prices do remain higher, I do think we'll be entering into '22 with a higher budget cycle than what we experienced in '21. So hopefully, we're going to continue to see some increase in activity. And again, we think most of that activity is going to be directed towards super spec type capacity. We think customers' expectations are going to grow in terms of both performance and wellbore quality. So I think that positions us well for additional growth. But again, we can't really give you a rig forecast past Q3.
Mark Smith: I would just add on, Waqar, back on the international part of that. You're right. I think as we look at these through our planning horizon, as John has said, and we've said, we're very focused on international opportunities. But as you point out, it's a longer sales cycle and I think those would be more calendar '22 as we think fiscal '22, to the extent that they come to fruition. But the good news is we are seeing more bidding activity, tendering activity internationally in various countries. And it's a long process, as you mentioned in your question, so we'll just stay tuned for that. But not in this year's fiscal model.
Waqar Syed: And just one other question. The talks of labor strikes in Argentina. Is that affecting your activity there?
John Lindsay: Waqar, there was some health care workers that were striking down there, blocking roads to the walk . So I think as of yesterday, those have stopped. So that kind of put a pause in a lot of activity down there, but hopefully, that gets up and running relatively soon.
Operator: Our next question will come from Vaibhav Vaishnav at Coker & Palmer.
Vaibhav Vaishnav: So your daily costs decline significantly and obviously, you guys are doing a lot around cost savings. So maybe if I can ask how much more cost savings to come and maybe time line? I mean, essentially, what I'm trying to think about is, let's say, if we think about HP rigs, call it, 150, 175 rigs working eventually. How should we think about that daily operating cost?
John Lindsay: I'll give you a couple of things to think about because we're not ready, as I mentioned in the prepared remarks, to give you specifics yet on timing or dollar amounts, but we're very focused on cost management. Just a couple of things. We've started, as I mentioned, scrapping process for previously decommissioned rigs, previously impaired rigs. And another example that we will move forward with consolidation of yards as scrap sales are completed. Last year, we had to make some tough choices on cost. As John talked about, the reorganization we did and that involved removing much of the labor element of consolidating our seven North American districts to four regions. We are now working towards the physical structural geographic footprint to align with those four regions, and that's, again, kind of consolidating yards in that specific example. And these changes will result in stack yard closures and forward cost savings related to everything they're with. The time line and impact around these is that specific initiative as an example, and many other things that we are working on now those initiatives are carrying forward and protracted, and we'll be talking more about that, especially as we move towards fiscal '22.
Vaibhav Vaishnav: And maybe just follow-up, if I think about your exposure to private rigs. Can you talk about like what's the average length of contract with private operators? And what I'm trying to think about is like, well, if commodity prices do go down, what is the risk of those rigs coming down?
John Lindsay: It's really across the board. I mean we have spot market exposure to the public companies as well. So it's kind of hard for us to pull that out and give you some information that would really help in that case.
Mark Smith: Yes, I'll just add on there, yes. It's across the board. I mean we've had some private guys that were contracted earlier in the year and didn't add rigs when commodity prices moved up. So yes, again, there will be some that might retract. But yes, it's a really mix for us.
Vaibhav Vaishnav: And maybe if I can squeeze in one more. As we talk about reactivation cost, obviously, you talked about $6 million for this quarter and maybe if -- I guess like conversations are going forward with customers trying to push that reactivation cost to them. Is that fair to think like there should not be any reactivation cost not in a major amount starting fiscal fourth quarter?
John Lindsay: No, I think it's too early in the game for that. I'm sure we already have some commitments for rigs in Q4. We're going to do the best that we can. Again, sometimes that reactivation cost is captured through a term contract built into the day rate. So we would still potentially have some reactivation costs, but we're getting compensated for that over the life of the contract. So there's a lot of different examples on that. But no, Q3 would be too early.
Operator: And gentlemen, our next question this morning comes from the line of Chris Voie at Wells Fargo.
Chris Voie: Maybe just to start with a pretty high level question around efficiency. So in 2019, you saw a lot of dramatic increases in footage per rig and E&P presentations or if you just do the math. In 2020, obviously, a pretty crazy year, tough to track with all the volatility. Now that we've got some -- obviously, the rig count is increasing pretty solidly but probably easier to measure at this point. If I think about the drivers to increasing footage per rig, there's higher rate of penetration with more super specs and service excellence, that's in your control. And there's bigger pad sizes, fewer modes that’s in your customers’ control. I'm just curious if you can give any perspective on whether increasing footage per rig has leveled off compared to the exit rates in 2019, or if it continues to increase.
John Lindsay: Chris, I don't have a sense for how 2021 is measuring up to 2019. But I think, generally speaking, in the US, we continue to improved cycle times. I can really only speak to the H&P rigs. But we're improving cycle times. We're also continuing to drill longer laterals. All the things that you mentioned play into that. I will say on the technology side, as I mentioned in our prepared remarks, less tortuosity and having fewer hard turns downhole has an impact on downhole tool life. So fewer trips, which also enhances the speed of drilling the well. So I think we still have runway ahead of continuing to improve performance. Automation is going to contribute to that. We're going to continue to see technology advances, both downhole as well as with software. So I think we're going to continue to see that happen.
Chris Voie: And then for a follow-up, this is more of a clarification. But in the prepared remarks, I think you're talking about a bunch of rigs this quarter rolling over to lower rates after contracts expire. But then in one of the Q&As, I think there was a commentary that maybe suggested that leading edge now might be near or exceeding the portfolio average. So if we just think about gross margin per rig, excluding reactivation costs, is that leading edge now near the portfolio average or is that going to keep ticking down maybe as you head into 4Q from 3Q?
Mark Smith: No, it's not the portfolio average. I think what John was talking about in Q&A is it's up from the recent bottom of the spot, if that makes sense. So we continue to have rigs rolling off a contract. They're repricing in the current environment, but that spot has moved up from our low rig count back in August of 2020. And in addition to that, we are with our sales team and working with our customers and looking at win-win solutions, leading with those discussions for the renewals with performance based contracts. So that to the extent that we're successful there and getting a better outcome for the customer, we also get a better uplift with the bonus for hitting KPIs at the end of the job.
Operator: And this does conclude today's Q&A session. I am pleased to turn the floor back to Mr. John Lindsay for any additional or closing remarks.
John Lindsay: Thank you, Jim, and thanks again to everyone for joining us on our earnings call today. As we've outlined, we have several strategic objectives that the company is working on. We believe are going to continue to bring about an evolution in our industry. The industry, obviously, will continue to face challenges, but I believe that H&P and our people are up to the challenge. So we're going to keep working very hard to keep improving it. So thank you again for joining us today, and have a great day.
Operator: This does conclude today's program. Thank you for your participation. You may disconnect at any time.
