Helmerich and Payne Inc (HP) 2022 Q1 法說會逐字稿

Good day, everyone, and welcome to today's Helmerich & Payne's Fiscal First Quarter Earnings Call. (Operator Instructions) Please note, this call may be recorded.

It is now my pleasure to turn today's program over to Dave Wilson, Vice President of Investor Relations. Please go ahead.

Thank you, Gretchen, and welcome, everyone, to Helmerich & Payne's conference call and webcast for the first quarter of fiscal year 2022. With us today are John Lindsay, President and CEO; Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us, after which we'll open the call for questions.

Before we begin our prepared remarks, I'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based upon current information and management's expectations as of this date and are not guarantee to the future performance. Forward-looking statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements.

We will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You'll find the GAAP reconciliation and comments and calculations in yesterday's press release.

With that said, I'll turn the call over to John Lindsay.

Thank you, Dave. Good morning, everyone. We appreciate you joining us today for our first fiscal quarter earnings call. 2022 is off to a strong start.

I continue to be encouraged by the progress the industry has made on its path to recovery from the pandemic-induced market collapse in 2020. Rig activity continues to increase with much stronger oil and gas prices, resulting in our customers' 2022 budgets being reset at higher levels than last year. We believe customers will maintain capital discipline with their budgets, as they did in 2021.

The primary theme for my remarks today will be rig pricing in the U.S. Over the past 7 years, the oil and gas industry has experienced 2 of the worst downturns in history, and like all downturns, rig rates plunged overnight to very low levels in concert with commodity prices and customer budgets. Fortunately, we've seen oil and gas prices make a rapid comeback since going negative. Conversely, pricing in the oilfield services space has improved only marginally.

As we sit here today, with commodity pricing hovering near 8-year highs, we're seeing an improving and tightening rig market. We're also delivering record drilling performance and have responded with substantial investments over $60 million in OpEx alone that were required to recommission over 110 rigs since our rig count bottomed in August of '20. Against this background, average rig pricing has improved only nominally up to this point.

Our customers have benefited from higher commodity prices. But from an oilfield service provider perspective, and particularly as a driller, we need substantially higher pricing in order to generate the returns required to attract and retain investors. Oilfield services revenues must increase substantially if the upstream oil and gas industry is to remain vibrant, technology-driven and sustainable in the future.

During the first quarter, demand for super-spec rigs in our North America Solutions segment continued to grow by 27 recommissioned FlexRigs. We're currently experiencing a very tight market, especially for rigs that were active just prior to the pandemic hitting the U.S. in March of 2020. While the second fiscal quarter is expected to be more moderate in terms of rig adds, we expect to add a total of 11 to 21 FlexRigs during the quarter, which is still a healthy increase.

The company is well positioned for this opportunity, given our ability to provide superior rigs, people and technologies that culminate in a compelling value proposition for our customer, particularly in this improved commodity price environment. Our market share has recovered from below 20% at the height of the pandemic to the highest levels we've ever achieved in the horizontal market, and our teams have worked hard to position us as the leading drilling solutions provider.

Leading-edge pricing and margins are growing as a result of super-spec rig demand and the need to offset the operating costs associated with reactivating idle rigs as well as other general operating cost inflation. Assuming oil prices remain strong, we plan to continue to push pricing in the coming quarters as the scarcity of readily available super-spec rigs becomes more prevalent. We believe this upward rig pricing momentum should be commensurate with the value H&P delivers to the customer.

Achieving a fair return on investment is essential to sustaining capacity and innovation in any business. However, at present, we see current pricing environment as an impediment to the capital investment required to relieve the tight supply of capable rigs. H&P remains the market leader within the industry with the largest fleet of active rigs as well as the most super-spec rigs available to be deployed to satisfy future demand. Our strategy for new capital investment going forward will be tightly aligned with that of our customers, and we'll continue to be disciplined and return-focused.

As we've discussed on previous calls, the industry pricing model needs to evolve from a pure day rate to a commercial model that rewards performance, wellbore quality and value creation for the customer. We've grown our performance-based contract model to approximately 40% of our active fleet, and our teams continue to partner with our customers to drive better outcomes. We've taken a portfolio approach using different iterations of performance contracts to determine which types make sense for us and the customer under a variety of scenarios.

Our rig pricing strategy is also dynamic, encompassing inputs derived from customer demand, pricing algorithms, reinvestment metrics and industry sentiment. As we look ahead to pricing in the strengthening and tight rig market, we see revenue per day needing to approach $30,000 for H&P to start generating margins that support cost of capital returns. And fortunately, several of our leading-edge rigs are beginning to approach this level of revenue today.

Our new commercial models are especially designed to include our automated software solutions that enable value creation through speed of execution and drilling times and even more importantly, by enhancing overall wellbore quality. The uptake by customers of our digital solution offerings is increasing. And with more rigs working, there are a growing number of new customers who have yet to be introduced to these technologies.

We are encouraged by our progress, but we also know from past experience that introducing innovation in our industry requires patience, and that adoption will not happen in a linear fashion. This is particularly relevant when a portion of the benefits from wellbore quality accrues over time and will manifest value after a well has been drilled.

Now shifting to our International segment. And we're excited about our strategic alliance with ADNOC Drilling and the investment we made, and we look forward to further expanding that relationship as well as developing additional opportunities in the Middle East region.

Our activity in South America is improving slowly, and we remain encouraged by the prospects for additional growth in the coming quarters and beyond. While our long-term outlook is positive for both the Middle East and South America, in the near term, our rig count in the Middle East is expected to decline due to 2 unexpected rig releases in Bahrain.

We published our inaugural sustainability report in December, and hopefully, many of you have had the opportunity to read it and appreciate the additional transparency into how we operate as a company. The report highlights how our improving drilling efficiency not only provides economic benefits to our customers but also the improvement in the collective environmental emissions profile of H&P and our customers.

As an industry, we continue to lower environmental impacts by creating new solutions to reduce those impacts as well as developing pathways to a smooth energy transition. In this challenging transition period, we're actively working with our customers to provide synergistic solutions that can achieve both their economic and environmental objectives.

Despite the industry challenges faced during the past couple of years, we remain focused on long-term opportunities and a strong disciplined approach to capital allocation. In this way, we will continue to strengthen the company to build a return profile for the long-term benefit of our shareholders. We've maintained a very strong balance sheet, and Mark will go into more detail regarding our capital allocation strategy and our ability to generate free cash flow in the second half of fiscal 2022.

This would not be possible without the hard work and dedication of H&P employees, both past and present, who continually set the standard in the industry. Over 100 years of drilling experience, combined with our uniform FlexRig fleet and industry-leading automation solutions places us in a great position as we move forward. Our rigs, automation solutions and our digital portfolio provide compelling value propositions for both North America and international markets.

The momentum we built during fiscal '21 carries into fiscal '22 with a fresh sense of optimism. We look forward to strengthening our partnerships with new and existing customers and developing drilling solutions that contribute to our mutual long-term successes.

And now I'll turn the call over to Mark.

Thanks, John. Today, I will review our fiscal first quarter 2022 operating results, provide guidance for the second quarter, update full fiscal year '22 guidance as appropriate and comment on our financial position.

Let me start with highlights for the recently completed first quarter ended December 31, 2021. The company generated quarterly revenues of $410 million versus $344 million in the previous quarter. As expected, the quarterly increase in revenue was due to higher account activity in North American Solutions as operators committed to calendar 2022 drilling activity.

Total direct operating costs incurred were $301 million for the first quarter versus $269 million for the previous quarter. The sequential increase is attributable to the aforementioned additional rig count and the related rig commissioning expenses in the North America Solutions segment.

General and administrative expenses totaled approximately $44 million for the first quarter, lower than our previous quarter and slightly lower than our previous first quarter guidance. I will comment on SG&A guidance later in these remarks.

During the first quarter, we realized a gain of approximately $48 million related to the fair market value of our ADNOC Drilling investment, which is reported as a part of gain on investment securities and our consolidated statement of operations. As discussed on last quarter's call, we called our legacy 2025 maturity bonds using the proceeds from our September refinancing and recognize the make-whole premium together with the unamortized discount and debt issue costs of approximately $60 million during the first quarter. Our effective Q1 tax rate was approximately 13%, which is outside of our previously guided range as we recorded a discrete tax expense and are projecting additional foreign tax for fiscal year 2022.

To summarize this quarter's results, H&P incurred a loss of $0.48 per diluted share versus a loss of $0.74 in the previous quarter. First quarter earnings per share were negatively impacted by a net $0.03 loss per share of select items, as highlighted in our press release, including the aforementioned gain on investment securities and debt extinguishment costs. Absent these select items, adjusted diluted loss per share was $0.45 in the first fiscal quarter versus an adjusted $0.62 loss during the fourth fiscal quarter.

Capital expenditures for the first quarter of fiscal '22 were $44 million, below our previous implied guidance. This is primarily due to the timing of spending, which has shifted to the remaining quarters. H&P consumed approximately $4 million in operating cash flow during the first quarter of 2022, generally in line with our expectations. I will have additional comments about our cash and working capital later in these prepared remarks.

Turning to our 3 segments, beginning with the North America Solutions segment. We averaged 141 contracted rigs during the first quarter, up from an average of 124 rigs in fiscal Q4. We exited the first fiscal quarter with 154 contracted rigs, which was in line with our guidance expectations. As John touched on earlier, demand for rigs continued to expand heading into calendar 2022 producer budgets.

From October 1 through December 31, we added 27 rigs to our active rig count, including 2 walking FlexRig drilling rig conversions that were completed in fiscal Q1 and over 20 skidding rigs. Of note, for rigs added in the U.S. market in calendar Q4 across the industry, HP skidding super-spec rigs made up roughly 30% of all industry rig count additions according to the Enverus rig count.

Our U.S. onshore market share increased in the first quarter and was approximately 26% at calendar year-end '21 for total horizontal active rig count and 35% for super-spec active rigs. As I will discuss in the capital expenditures remarks later, we will focus on putting our idle capacity to work for margin accretive returns, notwithstanding any market share dynamics.

Revenues were sequentially higher by $48 million due to the previously mentioned activity increase. Segment gross margin was $84 million, at the top end of our November guidance and sequentially higher than the fourth quarter of fiscal '21's $69 million. Overall OpEx for the North America Solutions segment increased on a sequential basis due to the aforementioned 21% increase in our rig count quarter-on-quarter and the associated reactivation costs. The reactivation costs were $20.5 million during the quarter compared to $6.6 million in the prior quarter. Including the impacts of reactivation costs in the quarter -- excluding, I should say. Excluding the impact of reactivation costs in the quarter, per day expenses fell by more than $1,000 per day to just below $15,000 a day as we began to benefit from increased scale, coupled with cost management efforts undertaking since the pandemic, including the first quarter sale of 2 margin-neutral service lines, rig move trucking and casing running tool services.

A couple of comments are in order regarding reactivation costs. As we have seen in previous cycles and have stated on recent calls, there is a positive correlation between the reactivation cost per rig and the length of time the rig has been idle. This factor, combined with inflation, is putting upward pressure on the reactivation cost per rig, but we are working hard to minimize those costs. As a reminder, most of our rigs were stacked back in April and May of 2020. Most of our 27 first fiscal quarter '22 reactivations have been idle on average of 540 days or over 18 months.

H&P currently has 42 rigs remaining that worked within the past 21 to 24 months, rigs that were active as the U.S. was heading into the pandemic. This is the largest portion of swing supply in the U.S. To remind, as we have discussed on prior calls, reactivation costs are mostly incurred in the quarter the rig starts to turn to the right and the absence of such costs in subsequent operating quarters is margin accretive to the company.

Looking ahead to the second quarter of fiscal '22 for North America Solutions. As I mentioned earlier, we ended Q1 near the midpoint of our exit guidance range. The activity level is continuing to grow, albeit at a more moderate pace than the first quarter, driven in part by public company operators who are working to fulfill their calendar '22 budget levels. As of today's call, we have 164 rigs contracted, and we expect to end the second fiscal quarter of '22 with between 165 and 175 contracted rigs.

As noted in John's comments, performance contracts now make up about 40% of contracted North America Solutions rigs. As discussed on previous calls, contract bonus potential is not included in backlog since it is contingent upon achieving specific contractual criteria, which is typically measured at the end of the well. While completed wells within the quarter with performance bonuses are both billed and recognized within the quarter, the amount of potential bonus for wells in progress as of December 31 that could not be recognized until well completion was approximately $2.7 million.

As such, when in-progress wells are completed in the second quarter, the actual bonus earned will be recognized. This potential -- this bonus potential at quarter end has been steadily growing quarter upon quarter as the proportion of the performance contracts across our fleet increases. Our current revenue backlog from our North America Solutions fleet is roughly $493 million for rigs under term contract. And as I noted, this figure does not include additional margin above base day rate that H&P can earn if performance KPIs are met once wells are completed. In the North America Solutions segment, we expect gross margins to range between $100 million and $115 million, inclusive of the effect of the $11 million of reactivation costs.

I will now turn our attention to inflationary and supply chain considerations. As a reminder, from our November call, we increased labor rates in early December, which, although a margin neutral pass-through, will be accretive to full second quarter costs. We are still seeing some inflationary pressures on materials and supplies, as mentioned last quarter. Although some pricing and pressures appear to be beginning to stabilize, we do expect recurring per-day expenses to increase above $15,000 per day in fiscal Q2. As it relates to supply chain access to parts and materials, we continue to utilize our proactive approach to alleviate supply chain challenges in order to avoid a material impact to our ongoing operations. That approach includes remaining vigilant about inventory and actively engaging with our suppliers and partners in order to be ready to adjust quickly as developments unfold.

Regarding our International Solutions segment. International Solutions business activity increased by 2 rigs to 8 active rigs at the end of the first fiscal quarter. We added a rig in Argentina and had a rig commence work in Colombia that had previously been delayed. International results were below guidance due to the start-up of these rigs and other transitory costs.

As we look toward the second quarter of fiscal '22 for International, our activity in Bahrain will decrease from 3 rigs to 1 active rig due to notification in January regarding changes in the customer's drilling schedule. Conversely, we expect to add another rig in Argentina as activity there gets to 5 working rigs plus a second rig in Colombia during fiscal Q2. In the second quarter, we expect to have between a $2 million loss and breakeven results aside from any foreign exchange impacts.

Turning to our Offshore Gulf of Mexico segment. We still have 4 of our 7 offshore platform rigs contracted, and we have active management contracts on the 3 customer-owned rigs, 2 of which are on active grade. Offshore generated a gross margin of approximately $8.6 million during the quarter, which was above the high end of our estimates. As we look to the second quarter of fiscal '22 for the Offshore segment, we expect that Offshore will generate between $6 million to $8 million of operating gross margins.

Now let me look forward to the second fiscal quarter and update full fiscal year '22 guidance as appropriate. Capital expenditure for the full fiscal year 2022 are still expected to range between $250 million to $270 million, with remaining spend distributed fairly evenly over our last 3 fiscal quarters. As John emphasized earlier, we are closely assessing rig reactivations for appropriate contract terms and economics in light of increasing OpEx reactivation costs, maintenance CapEx accretion and required return on investment.

I'll mention again that H&P has 42 super-spec FlexRigs that have been idle just under 2 years. Further, we have another 26 super-spec FlexRigs that have been idle longer than 2 years. The significant U.S. swing capacity can be deployed for the right economics of price and term duration. Our guide post in this process are hurdle rates at or above the OFS industry cost of capital.

A few observations on H&P's U.S. FlexRig fleet and U.S. supply. Given the available idle rigs that can be deployed in time, we see no need for new build capacity on our mid- to long-term planning horizon. H&P's fleet is approximately 9 years old on average and has a composite weighted average accounting life of 15 years. However, the economic life of the rig structure is 30-plus years with major rig components, including blowout preventers, top drives and engines regularly refurbished via our maintenance CapEx, thereby extending their economic lives for complete rig assembly to have a long horizon of economic return generation.

We regularly conduct R&D efforts for rig improvements, but currently see no breakthroughs that would supplant today as a uniform FlexRig fleet.

Our expectations for general and administrative expenses for the full fiscal '22 year have not changed and remain at approximately $170 million. However, we expect second quarter SG&A to be higher than the final 2 quarters of the year as some expected Q1 expenses were delayed into Q2.

We are now estimating our annual effective tax rate to be in the range of 10% to 16% with no change to the previously guided range of anticipated cash tax of $5 million to $20 million. The difference in effective rate versus statutory rate is related to permanent book-to-tax differences as well as state and foreign income taxes.

You will notice that our income statement has a new line, gain on reimbursement of drilling equipment, which has historically been included in the line item, gain or loss on sale of assets. We broke this out to provide more transparency around income that is derived from our normal recurring operations and is used to offset a portion of gross maintenance CapEx. These amounts were primarily derived from reimbursements we received from customers for tubular goods that are lost in hole or damaged beyond repair.

Now looking at our financial position. Helmerich & Payne had cash and short-term investments of approximately $441 million at December 31, 2021, versus an equivalent $570 million at September 30, 2021, after backing out the 2025 bond extinguishment. This sequential decrease is largely attributable to our recent share repurchases, seasonal cash outlays and working capital lockup.

During the latter half of the first fiscal quarter, we saw a combination of excess liquidity and an attractive opportunity to repurchase some of our shares at prices that we believe to be value accretive. Through January 28, we have repurchased approximately 3.1 million shares total for roughly $76 million. Approximately 2.5 million shares were repurchased in December under our evergreen annual share repurchase authorization of 4 million shares per calendar year. To date in calendar '22, we have repurchased about 600,000 shares under the calendar '22 4 million authorization. These recent repurchases augment our long-standing dividend as we allocate excess cash.

Including our revolving credit facility, liquidity was approximately $1.2 billion at December 31. Our debt to capital at quarter end was approximately 16%, and our net debt was approximately $101 million. We currently expect our trailing 12 months of gross leverage turn to reach our goal of less than 2x outstanding debt during this fiscal year.

H&P's debt metrics continue to be a best-in-class measurement amongst our peer group. And as a reminder, our sole remaining long-term debt carries a 2.9% interest rate and matures in 2031. Our credit rating remains investment grade.

As mentioned on our last call, working capital is the use of funds as our rig count rises, and that was substantial during the quarter given the addition of 27 rigs.

Our accounts receivable at fiscal year-end of $229 million grew by $53 million to approximately $282 million. The preponderance of our AR today continues to be less than 60 days outstanding from billing date, although historically, we have experienced seasonal calendar year-end collection slowdowns as we just did. Consolidated inventory increased slightly for the first time in over a year.

Finally, as a reminder, our annual short-term incentive bonus compensation and our ad valorem taxes accrue throughout the year, and we pay all of the compensation and most of those taxes during the first fiscal quarter. With that as background, as expected, fiscal Q1 saw lower cash flow from operations than we expect from the next few quarters due to the rig ramp-up and the seasonal cash expenditures. As of today, we expect to end the fiscal year with between $400 million and $450 million of cash and short-term investments on hand, down from the range of $475 million to $525 million guided on the November call due to the aforementioned share repurchases.

As I mentioned on the November call, we expected to use a moderate amount of cash on hand as we worked towards the calendar year-end 150-plus rig count activity level. The as-expected growth in rig count early in the fiscal year provides a platform for cash generation in the second half of the year that point forward fully covers our cash usage, including our dividend and sets the stage for cash accretion.

That concludes our prepared remarks for the first fiscal quarter. Let me now turn the call over to Gretchen for questions.

(Operator Instructions) And our first question comes from Ian MacPherson from Piper Sandler.

So curious on lead times. Obviously, you have very clear contracted visibility into your fiscal Q2 rig adds. We have a higher oil price deck than we had last time we spoke, clearly more impetus to drill in the second half of the calendar year. I wanted to hear what your expectations are for bottlenecks to continue to add rigs through calendar Q3 and Q4 and what your delivery lead times was like, if I'm a private E&P with 0 or 1 rigs running today and I need another one. I know I'm not just waiting on HP, I'm waiting on other equipment providers as well. But how easy or difficult will it be to deliver the incremental rigs in the back half of the calendar year?

Sure, Ian. From an equipment perspective, I don't know of any particular bottlenecks that we have, at least for the foreseeable future, for the next couple of quarters based on what we see right now. I would say kind of going back to the theme, the biggest -- probably the biggest bottleneck to growth for us is just being able to get pricing at a level that makes sense to make the investments that we need to make in order to recommission the rigs. There's obviously some CapEx associated with that as well.

But most of that are just pure recommissioning costs and just getting the pricing up. I think -- I'm trying to think past maybe the next several quarters or maybe into 2023. I know BOPs are a potential bottleneck that are out there. Dave, Mark, anything else that you are aware of.

No. No, John.

So Ian, I think we're in pretty good shape with the fleet and -- the fleet that we have, the inventory that we have on hand as well as the internal capabilities that we have to repair and get equipment in working order.

Okay. If I heard you correctly, and correct me if I misstate this. You said, I think, 30% of the industry rig adds last quarter were your skidding rigs. And if that's the case, are those customers that are accepting skidding rigs with an expectation to be upgraded to a fully walking rig at a later point in time? Or are those applications where the skidding rig is just what they need? Because I do think that, that was a point of maybe controversy coming out of last quarter's discussions.

Sure. No, we have customers that have a very high demand for skidding rigs, that's their preference. Their preference, it's the rig they've used for several years now, and that is their preference, whether it's a Flex 3 or a Flex 5. There are some customers that have a preference for the walking application.

When I say preference, it's really driven by factors related to their location and well configuration. But we also have a lot of customers that use both. I mean they have both the Flex 3 skid, Flex 5s and they have the Flex 3 walking. So it's pretty much across the board. Mark made a great point with the adds that we've seen during the quarter and really during the year, the skidding rigs have picked up pretty substantial amount of market share.

Our next question comes from Scott Gruber from Citigroup.

Mark, can you just give me again the expected cash balance at fiscal year-end? I missed that earlier.

Sure, Scott. It's $400 million to $450 million. So it's really just down by the $75 million approximate of share repurchases that we discussed.

Got you. I appreciate that. And just thinking about cash return strategy longer term, your free cash potential is going to improve here in the second half of the year into '23. Yes, just thinking about how you buyback, how much emphasis are you going to place on those into the future, is it going to be an increasing point of emphasis for the company into the up cycle? And longer term, do you believe that cash flow per share growth should be a strategic priority of the company into the energy transition?

I'll start off, and then John or Dave chime in. But Scott, absolutely, growing our cash flow is paramount in a lot of what the theme that John discussed around pricing is related to, absolutely. As it relates to these particular buybacks, as I mentioned, we thought there was value dislocation and we thought it was very opportunistic, couple that with what we believe to be excess liquidity on hand, couple that with, as I mentioned, looking ahead in our debt metrics for the trailing 12 months during this fiscal year, getting below 2x turn. I add all those things up with the $4 million -- I mean the 4 million share preauthorization, it just seemed like the prudent investment to make.

We will continue to use that as a lever together with our long-standing 60 years of dividend payments. And one of the really great things about looking ahead is that these are the discussions that we as a management team are having today and with our Board about capital allocation and the cash build that we'll be having. So these options are the ones that are front and center for us, looking at the long-standing dividend, the share buyback potential and who knows maybe a special dividend as we move through time. But we're still formulating those. We're still deliberating the exact methods. More to come on that.

Got it. And then just another one on the appetite for performance-based contracts. Have you seen a marked shift in the appetite to enter those performance-based contracts over the last 3 months? And can you provide some more color on the terms and conditions that are starting to become more favorable for you in terms of achieving the bonuses?

Yes, Scott, it's interesting. As you know, time flies. It's been 2 years since we first started talking about new commercial models and changing away from the day rate model. And those first several quarters, it was pretty slow adoption. But as we've said, we're around 40% of our working rigs today. It's really a partnership working with our customers.

And what's great about it is there's a portfolio of different options that we can provide for the customer working together based on what's most important to them in terms of the outcomes that they're looking for or the areas that they're challenged with in terms of driving performance. So there's no doubt that as you look at kind of a base revenue per day, that number has moved up significantly on the performance base just like our spot pricing.

And then as you look at leveraging the technology components and figuring out, again, back to what are the outcomes that we're trying to provide for the customer, there continues to be an upside for us. So yes, I think it's a good trend in the industry. And again, we're getting a lot of uptake from new customers. A lot of growth with customers have been working with us on this all along, but we also have some new customers as well.

Our next question comes from Taylor Zurcher from Tudor, Pickering.

I wanted to circle back on some of the pricing comments you made. John, you talked about a few of your -- I think several of your rigs approaching $30,000 of revenue per day, which is materially higher than what you reported this quarter, I think somewhere in the neighborhood of $23,000 in revenue per day. So just curious, when it comes to that $30,000 a day number, I imagine that's including the whole host of solutions, including digital that you provide and might be more on the performance versus traditional day rate side.

But should we be thinking about close to $30,000 a day as true leading edge, whether you're on the traditional day rate model or the performance-based model? And just more importantly, with all these inflationary items impacting cost, how should we be thinking about that $30,000 a day translating into margin? Should we be using a $15,000 type cost number there?

Well, Taylor, starting on the cost side, today, $15,000, but our goal is to get there, I think what we guide for a little higher than $15,000.

Median guidance. We just gave the gross margin guidance.

As I mentioned in my prepared remarks, we do -- we will get over $15,000 in this quarter, Taylor, so somewhere between $15,000 and $15,500.

Yes. So I think the point is that it is a -- this $30,000 revenue per day, it is a very tight market. We're faced with, obviously, significant precom costs. Everybody has seen that. We've had substantial investments in super-spec capability and performance. You look at oil and gas prices and how they -- they're really at 8-year highs.

And going back to that period of time when we last saw pricing, oil prices at that level, our average day rate on a rig was between $25,000 and $26,000 a day. So our costs are up $3,000 to $4,000 compared to that same period of time. So as you start looking at that and looking at the inflation, it's just that $30,000 a day revenue -- revenue per day really makes a lot of sense. Obviously, you don't get there overnight.

And -- but that's part of the point to make, is that in a downturn, rates drop immediately overnight. And as you start to see the market improve, we're 17 months since the bottom, and we've had really -- we're appreciative of the increases, but they're pretty nominal when you compare to where we were at the bottom in terms of average pricing.

So we got to get that average pricing up. And again, we won't get there overnight, but we have evidence that it's possible. We have it out in the market today, with customers that are really seeing a lot of value with the performance-based contracts and the technology solutions that we're providing.

Understood. And a follow-up there, just on the contract book. It sounds like based on that response from some of your earlier comments that pricing is becoming a bit of an impediment to reactivate a bunch more rigs. And so as I look at your contract book, you've had a bunch of new term contracts, but not many with durations of longer than 12 months. So just curious if you could frame for us what customer appetite is today to lock in terms longer than 12 months? And what your appetite is today to lock in terms longer than 12 months at current pricing?

Yes. So I think it's -- when you say current pricing, not current averages, but our current leading edge, I mean, we have entered into 18 months and 2-year terms or in the process, I'm not certain if they're signed now. I think some of them are. But they're in the 18 to 24 months, and they're at that leading edge pricing that I'm talking about, mid-20s in terms of a base rate and then you have technology solutions and other performance criteria in order to get that pricing up from there.

And just to give you a little color on some specifics within that. Of the 27 rigs we added during the first quarter, Taylor, 12 were on term, 15 were on spot. But more recently, the 10 we've added this calendar year to date, 7 of those are on term and 3 are on spot.

Yes, we're definitely looking at term contracts. We have customers that are interested in term contracts. So our desire would be to keep doing that. So keep in mind also, we have rigs that are rolling off of term during the quarter. And some of those rigs will roll back into term, of course, at much higher pricing would be our expectation than where they are today. I would imagine some of those rigs would also roll into performance-based contracts as well.

Our next question comes from John Daniel with Daniel Energy.

I missed a lot of the Q&A. So if I ask the same question that one of my colleagues and peers did, I apologize. So John, a question for you. Since you've been running HP, how would you characterize your involvement in porting a price or perhaps blessing a price quote historically? And then how would you categorize that involvement today?

Well, I'm definitely not involved on a day-to-day basis. But clearly, in terms of setting pricing and expectations, I'm involved with that. But the overall leadership team, we're weighing in on that. One of the things -- it's interesting, John, it's a great question. As I think about that, there's benefits to being in this business a really long time. And there's also things that work against you over time because you begin to ask yourself, so why does -- again, in a down cycle, as I already said, rates drop overnight, in an up cycle as it starts to improve, it moves very, very slowly. And where is it written down that it has to be that way.

So as you go back into looking at the actual data, we've had a really tight market now for a couple of quarters. Even though there's available capacity, it's a really tight market for lots of reasons. So we definitely spend a lot of time on pricing strategy. And we're using tools today that we haven't used previously that utilize data in a much more effective way. So it's not just a gut feel. It's -- again, we've got a data set that we fully understand that it's not just a maybe, it's a certainty that pricing needs to improve.

No, I would agree with that. But I guess, a bigger question and not meant to be rude, but if oil prices and commodities keep bleeding up, do you see yourself getting to the point where you say this is the law and this is how we're going to run it? Or is that a little bit too much being of a dictatorship on your part? I'm just curious how you'll approach that point.

Well, John, our -- we're in the customer service business, and I have been doing this a long time. And I'm not in the habit of dictating to customers. Obviously, in a tight market, there's a lot of demand, and there's little supply. But again, I think in most cases, John, our customers, I mean they're true -- it's a true partnership. We're working together. We -- I mean let's face it, we're obviously a public company that has to make better returns for our shareholders, and we're trying to do the same thing for our customers. So we're really working arm in arm trying to make this happen.

Fair enough, and that wasn't intended to be a (inaudible).

I know, John. You'd never do that.

No, I'm trying not to. So the next one for me, and if this was asked, I apologize. But if a customer called today and said, "Hey, I need a cold stacked rig, I want you to bring it back," realistically, what's the time from today when that thing could hit the field?

What's the what? I'm sorry, John.

Could you repeat that, again?

Like bringing a cold stacked rig back, the realistic time frame to having that out?

I haven't checked on that lately, John. But I think, generally speaking, we've got a couple of weeks to pull people together, probably 4 to 5 weeks in general to get everything ready. Six months ago, it was probably 2 weeks. And a year ago, it was a week. So it does take longer. You have to also realize that just like last quarter, we put 27 rigs into the market. And again, hopefully, this quarter will be closer to 20.

Got it. Fair enough. And the last one for me, and this can be a gut answer because you might not have the data in front of you, but just as you think about the inquiries that exist today that you would call a real inquiry, if you will, sort of bracket what percent would be integrated versus just remaining public versus private, if you could? A guess is fine.

I think just the mix between private and public, I think it's 50-50. It's probably...

No, we got about 40% that are private in terms of rig count, and then the other 60% are public. And John, within that public, you have 10% -- a little less than 10% is the majors.

But what about the inquiry? He asked about inquiry?

That, I don't have the data on.

Yes, pretty similar. We don't have in front of us, but I think it's pretty similar, John.

Our next question comes from Derek Podhaizer from Barclays.

I just want to go back to the daily margin conversation. The fiscal 2Q guide implies margins look to stay kind of in the flattish range, excluding reactivation expenses. Can you talk about where you see them going in fiscal second half '22? The level of expansion driven by both, the revenue side and then the cost side as well as rigs are added? Just thinking in the backdrop of, you talked about reaching $30,000 per day and those costs normalizing around that 15%, 15.5% range.

Derek, I'll start and then ask John to chime in here. It's really -- that cost range you just mentioned, I think, is a start. We will see, as I mentioned, the full effect of the labor increase hit us this quarter. And thankfully, we're starting to see some stabilization, as I mentioned, from an M&S perspective.

But what I'd say is that as we add more units, we continue to have assistance from just fixed cost absorption and scale as we really benefited from this quarter that we're talking about here today ending 12/31. We'll continue to see that, and we'll continue to manage cost aggressively as we have been, which has given us this result this last quarter.

But I think the opportunity set in front of us is really everything about the theme that John has been discussing from the outset of this call today, and that's getting the pricing up where we needed to be to get to the right return or a return that gets to our cost of capital as a hurdle rate and above it. That's where we have to be as a corporation, and that's where the upside can come from through the year.

John, anything to add to that?

Yes. I don't really have anything to add. I think that's it.

Would -- do you think you can get to a margin with a [9 handle] in the second half '22 fiscal?

Well, I think...

Excluding reactivation. Sorry, excluding reactivation.

Yes. Well, that's part of the opportunity, right, is that if this year follows like '21 whereas you've got the rig count ramp at the first quarter of the year -- of the calendar year and then it kind of flattens out, slightly up, then obviously, the rig recommissioning costs go away. And you're focusing -- your costs are down, and so you're focusing on growing the margin through pricing.

That's helpful. Switching over to more kind of the new energy theme. Geothermal, obviously, the news flow has been picking up there. I know you guys have a few equity investments helping out with some pilot programs. Maybe just kind of talk to that, how that's developing and progressing, just thinking about what's been put out by the California Public Utility with the 1,000 megawatts requirement for geothermal on the grid. Just any updates there on kind of how those pilot projects are developing?

Sure. Well, I'll let Mark talk about some of those developments and some of the investments. I will say that we do have a rig working today, drilling a geothermal well in Nevada, and it's drilling a couple of horizontal wells and a vertical well. And I think it's the first horizontal geothermal well in the U.S. that's been drilled. So we're excited about that and seeing some opportunities there.

Mark, do you want to talk about that?

Sure. Derek, as it relates to -- we're always looking at making financial and operational decisions for the long-term interest of the shareholders. And with regard to geothermal, we're looking at several different opportunities across the entire spectrum of geo opportunities instead of focusing just on one particular aspect. So different companies have different strategies to get to scale geothermal, and it's early in the development of that here in the U.S. and internationally.

The market is developing. It's taking time. Some of these technologies have to be proved out. The wells that John just described are part of that process. And we recently invested in 2 separate geothermal companies. One is pursuing a closed-loop concept that uses horizontal multilateral wellbores. The other is pursuing the enhanced geothermal system concept using horizontal drilling, as just discussed. And the collective investments to date of about $12 million.

And I'll add to that, that further in our pipeline, we're in various points of discussion with around 10 companies focusing on geothermal potential scale advancements globally. So we definitely are very active in that space. We've participated in some geothermal conferences and look forward to doing some more of that. We're making prudent and appropriate investments, we think, at the right sort of levels, and that includes also in-kind services as well. So more to come.

Our next question comes from Waqar Syed from ATB Capital.

John, first of all, congratulations on a great sustainability report. Really, it sets a new standard for sustainability reporting. So my congratulations to you and your team.

Thank you, Waqar. They've worked really hard on it. I'm proud of them.

Great. Great. Yes. My question is on the greenhouse gas emissions. We're hearing typically from the service industry is that the greenhouse gas emissions from the equipment and services at the well site go into the inventory of the E&P company or the customer. You've taken a slightly different approach to that. Could you maybe elaborate the approach that you took and why?

Yes. Waqar, I'll handle that one. For us to come out and say, "Hey, all our emissions are somebody else's problem," yes, I don't think that -- from a credibility standpoint, I don't think that would sit well with investors. So we're able to determine what our rigs emit as far as emissions. And so we're just being transparent that this is what we've been able to track over the past few years, do that.

So there is some shared accountability there, but we want to be -- have a full transparency and create some trust in the market by, "Hey, we're not shying away from this challenge, and we're going to meet it head on."

Great. Yes, you guys screen very well on our ATB ESG framework. So congrats on that. John, just one other question on the outlook for activity. Do you have any visibility into the second half? And do you see that there could still be some growth in the second half? Or do you think most of the rig activity increase in the U.S. is just first half weighted?

Yes. Waqar, it's a great question because we've been thinking about it very similar to '21. And of course, in '21, you had the fourth quarter of '20 and then the first quarter of '21 is where the ramp-up was. And we've really seen the same thing in the fourth quarter of '21 and the first quarter of '22. And our belief has been that it would mirror '21 very closely, even though there was some slight uptick in activity.

But obviously, there's -- it's hard to say past here. I think once we get to a more kind of a standard rig count, wherever that's going to land, and then you kind of start looking at the budgets that our customers have, we might be able to drive a little bit more out of the public company budgets from there. But it's hard to say. And of course, we don't have any -- really any insight into the private company besides just conversations that we have going on. But hard to say at this point. Our hope is, of course, is that we'll see some additional growth along with pricing improvements at the same time.

But does the industry's ability to move pricing up, how do you see that, like once the rig activity growth starts to slow down?

Yes. It's a really tight market, Waqar. There are just a very small number of rigs that have worked in the industry over less than 2 years' period of time. Like in other words, rigs that were working prior to the pandemic. So there's a large investment to be had. So I just think with the amount of activity that we have, and I'm talking primarily about the super-spec space, yes, I think we're close to 70% utilization. But again, the rig supply is very tight and same way with the people side of the equation. So I think there's going to be a lot of pricing power moving forward.

It appears that's all the time we have for questions. I will now turn the program back over to John Lindsay.

Okay, Gretchen, thank you. Thanks, everybody, for joining us today. We are very optimistic about the future and the momentum that we've garnered during the past several years. As we've said, we think we're very well positioned for the future. We've got a strong balance sheet. We've got the largest and most efficient super-spec FlexRig fleet, technology solutions, leading customer satisfaction delivered by the best people in the drilling business. So again, thank you for your time. We appreciate it, and have a great day.

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