© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, everyone, and welcome to today's Helmerich & 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. [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 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 reference to certain 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.
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 the 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 budget as they did in 2021.
The primary thing from my remarks today will be rig pricing in the U.S. Over the past seven years the oil and gas industry has experienced two 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 oil field services space has improved only marginally.
As we sit here today with commodity pricing hovering near eight 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 will require to recommission over 110 rigs since our rig count bottomed in August of ‘20.
Against this background, average rig pricing has improved only nominally upto this point. Our customers have benefited from higher commodity prices, but from an oil field 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.
Oil field 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 continue 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 the 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 or H&P to start generating margins that support cost of capital returns. And fortunately, several of our leading is rigs are beginning to approach this level of revenue today.
Our new promotion 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 uptick 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, 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 prospect 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 two unexpected rig releases and borrowing.
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 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 uniformed 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've 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 the 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 rig count activity in North America Solutions as operators committed to calendar 2022 drilling activity.
Total direct-to-operating costs incurred were $301 million for the first quarter versus $269 million for the previous quarter. The sequential increase was attributable to the aforementioned additional rig count and the related reconditioning 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 investments, 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 cost 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 this free 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 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 cost. After 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 was 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 three 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 rigs count, including two 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, H&P Skidding super spec rigs made up roughly 30% of all industry rig count additions account to the inverse 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 is sequentially higher that the fourth quarter of fiscal ’21 of $69 million. Overall OpEx for the North America Solutions Segment increase 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 impact 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 $1000 per day to just below $15,000 a day. As we began to benefit from the increased scale coupled with cost management efforts undertaking since the pandemic, including the first quarter sales of two margin neutral service lines, rig removed trucking and casing running tools 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 costs 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 of the 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 [ph] supply in the U.S. To remind, as we have discussed on prior calls, reactivation costs are mostly incurred in the quarter the rigs starts to turn to the right, and the absence of such costs and 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 actually guidance range, the activity levels 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 rig contracted and we expect to end the second fiscal quarter of ‘22 between 165 and 175 contracted rigs.
As noted in John's comments, performance contracts now make up about 40% of contract in North America Solutions rigs. As discussed on previous calls, contract bonus potential is not included in backlog since it is contingent on achieving specific contractual criteria, which is typically measured at the end of the well.
While completed wells was in the quarter, performance bonuses are both built 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 bonus potential at quarter end has been steadily growing quarter-upon-quarter as a proportion of performance contracts across our fleet increases.
Our current revenue backlog from our North American Solutions fleet is roughly $493 million for rates on return contract. As I noted, this figure does not include additional margin above base day rates that H&P can earn. The performance KPIs are met once wells are completed. In the North American Solutions segment we expect gross margins to range between $100 million and $115 million, inclusive of the effect of the $11 million 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 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 development unfolds.
Regarding our International Solutions segment, international solutions business activity increased by two rigs to eight active rigs at the end of the first fiscal quarter. We added a rig in Argentina and had a rig commence work in Columbia that had previously been delayed. International results were below guidance due to start-up of these rigs and other transitory costs.
As we look for the second quarter of fiscal ‘22 for international, our activity in Bahrain will decrease from three rigs to one active rig due to notification in January regarding changes in the customers drilling schedule. Conversely, we expect to add another rig in Argentina as activity there gets to five working rigs, plus a second rig in Columbia 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 four of our seven offshore platform rigs contracted and we have active management contracts on three customer owned rigs, two of which are on active rate. 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 off shore will generate between $6 million to $8 million of operating gross margin.
Now let me look forward to the second fiscal quarter and update full fiscal year ‘22 guidance as appropriate. Capital expenditures for the full fiscal year 2022 were still expected to range between $250 million to $270 million with remaining spend distributed fairly evenly over our last three 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 then have been idle just under two years.
Further we have another 26 super spec FlexRigs that have been idle longer than two years. The significant U.S. swing capacity can be deployed for the right economic of price and term duration. Our guide post in this process are hurdle rates at or above the OFS industry cost to capital.
The fee observations on HP'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&Ps fleet is approximately nine 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 or a complete rig assembly to have a long horizon of economic return generation.
We regularly conduct R&D efforts for rig improvements. We currently see no breakthroughs that was in plan 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 two quarters of the year and 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 was 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 receive from customers for tubular goods that are often old or damaged beyond repair.
Now looking at our financial position. The hummer campaign 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. The sequential decrease is largely attributable to our recent share repurchases, seasonal cash outlays and working capital lock up.
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 of prices that we believe to be value accretive.
Through January 28 we have purchased 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 longstanding 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 gross leverage turn to reach our goal of less than 2x outstanding debt during this fiscal year.
H&Ps 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 as a 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 with a 60 days outstanding for 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 accrued 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 at fiscal Q1 we saw lower cash flow from operations than we expect in the next few quarters due to the rig ramp up into 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 work toward the calendar year and the 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. Your line is open.
Good morning, John and Mark.
Good morning Ian.
So curious on lead times. Obviously you have very clear contracted visibility in your fiscal Q2 rig adds. Do you have a higher oil price deck than we had last time we spoke? Clearly, you know more emphasis 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 look like if I'm a private ENT with you know zero or one rigs running today and I need another one. You 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. You know 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 you know kind of going back to the thing, 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 you know that we need to make in order to recommission the rigs. You know there's obviously some CapEx associated with that as well, but you know most of that is just pure recommissioning costs and just getting the pricing up.
You know I think long – I'm trying to think past maybe the next several quarter or maybe into 2023, I know you know BOPs are a potential bottleneck that are out there. Dave, Mark, anything else that you’re aware of?
No, no John.
So Ian I think we're in pretty good shape with the fleet and at the end the fleet that we have, the inventory that we have on hand, as well as the internal capabilities that we have to repair and you know get equipment in working order.
Okay, thanks John. 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, you know we have customers that have a very high demand for skidding rigs, that's our preference. You know their preference, it’s the rig they’ve used you know 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. It's you know – and when I say preference, it’s really driven by factors related to the location and well configuration. But we also have a lot of customers that used both. I mean they have both, you know Flex 3 skids, Flex 5’s and they have the Flex 3 walking. So it's pretty much across the board. I thought you know Mark made a great point with you know the adds that we've seen during the quarter and really during the year. The skidding rigs have picked up pretty substantial in our market share.
Okay, great. Thank you, John.
Thank you.
The next question comes from Scott Gruber from Citibank. Your line is open.
Yes, good morning.
Good morning, Scott.
Mark, can you just give me again the expected cash balance at fiscal year-end? I missed that earlier.
Sure Scott. Its 400 and 450, so it's really just down by the 75 approximate of share repurchases that we discussed.
Got you, I appreciate that. And just you know thinking about cash return strategy longer term, you know your free cash potential is going to improve here in the second half of the year into ‘23. You know just thinking about how buy back – you know how much emphasis you’re going to place on those into the future. Is it going to be an increase from that emphasis for the company into the up-cycle and longer term you know do you believe that you know cash flow per share growth should be a strategic priority of the company here into the energy transition?
I'll start off and then John or Dave chime in. But Scott, you know absolutely growing our cash flow is paramount and a lot of what the theme that John discussed around pricing is related to it absolutely. As it relates to these particular buybacks, you know as I mentioned we thought there is value dislocation and we thought its very opportunistic. Couple that with what we believe to be excess liquidity on hand, and 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. You know I add all those things up with the $4 million – I mean the 4 million share reauthorization, it just seemed like the prudent investment to make.
We will continue to use that as a lever, you know together with our long standing 60 years of dividend payments and you know just one of the really great things about looking ahead is 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 and 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 maybe you can 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, you know it's interesting. As you know time flies. It's been two years since we first started talking about new commercial models and changing away from the day rate, the day rate model and you know those first several quarters it was pretty slow adoption.
But as we said, we're – you know around 40% of our working rigs today, you know it’s really a partnership working with our customers and you know 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 are looking for or the areas that they are challenged with in terms of driving performance.
So there's no doubt that you know as you look at kind of a base revenue per day, that that number has moved up significantly on a performance base just like our stock pricing. And then as you look at leveraging the technology components and figuring out you know again back to what are the outcomes that we are trying to provide for the customer, there continues to be you know an upside for it, so. Yeah, I think it's a good trend in the industry, and again we're getting a lot of uptake from new customers, you know a lot of growth with customers that have been working with us on this all along, but we also have some new customers as well.
I appreciate the color. Thank you.
Thank you, Scott.
Our next question comes from Taylor Zurcher from Tudor Pickering. Your line is open.
Hey John and Mark! Thanks for taking my question. 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 I'm just curious, when it comes to that $30,000 day number, I imagine that’s including the whole host of solutions, including digital that you provide and might be more on the performance for its traditional day rate side. But I mean, should we be thinking about close to the $30,000 a day as you know 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, now translating into margin. Should we be using a $15,000 type cost number there?
Well Taylor, starting on the cost side, you know today $15,000, but you know our goal is to get there. I think what we guided for a little higher than $15,000.
We didn’t guide them. We just gave the gross margin guidance.
As I mentioned then in my prepared remarks, we will get over $15,000 this quarter Taylor. So you know somewhere between $15,000 and $15,500.
Yeah. So I think that you know the point is that it is a $30,000 revenue per day. It is a very tight market. There's you know – we're faced with obviously significant pre-comp costs; everybody has seen that. We've had substantial investments in super spec capability and performance.
Yeah, you look at oil and gas prices and how they are really at eight year highs, and you know you’re going back to that period of time when we last saw pricing or 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 you know $3,000 to $4,000 compared to that same period of time. So you know as you start looking at that and you’re looking at the inflation, just you know that $30,000 a day 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 you know as you start to see the market improve, you know we’re 17 months since the bottom and we've had you know really, we’re appreciative of the increases, but they are 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, but 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 you know really seeing a lot of value with the performance based contracts and the technology solutions that we're providing.
Understood. Thanks for that, and a follow up there just on the contract book. It sounds like based on that response and some of your earlier comment 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 got 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 you know 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 a when you – you know when you say current pricing, not current averages, that’s our current leading edge. I mean we have entered into 18 months and two year terms or in the process – I am not certain if we’re signed now. I think some of them are, but they are in the 18 to 24 months and they are at that leading edge pricing that I'm talking about, you know mid-20 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.
Just to give you a little color on some specifics within that, of the 27 rigs we added during the first quarter Taylor, you know 12 were on term and 15 were on spot, but more recently the 10 we've added this calendar year to-date, you know seven of those are on term and three are on spot.
[Cross Talk]
Yeah, we're definitely looking at term contracts. We have customers that are interested in term contracts, so you know 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 you know some of those rigs will roll back into the term, of course at a much higher pricing. It would be our expectation than where they are today. I would imagine you know some of those rigs will also roll into performance based contracts as well.
Understood. Thanks for that. I appreciate it.
Thank you.
The next question comes from John Daniel with Daniel Energy. Your line is open.
Thank you and John, good morning. I missed a lot of the Q&A. Hopefully I don’t ask the same question as one of my good colleagues and [inaudible] I apologize. So John a question for you; since you've been running HP, how would you characterize your involvement in quoting a price or perhaps you know blessing [ph] a price quote historically and then how would you characterize that involvement today?
Well, I'm definitely not involved on a day-to-day basis, but clearly you know in terms of setting pricing and expectations, you know I'm involved with that, but you know the overall leadership team were weighing in on that.
One of the things you know that's interesting John, it's a great question as I think about that. You know 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 you know again, in a down cycle as I already said, rates drop overnight. In an up cycle it start 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, you know 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 utilized data in a much more effective way, so it's not just a gut feel. It’s a – 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. I guess a bigger question and not meant to be rude, but if oil prices can come or just keep leading 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, you know our – we're in the customer service business and you know I've 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 it's a true partnership. We'll work on it together.
You know I mean let's face it, you know 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.
Sure, nothing. It wasn't intended to be a gotcha question. I was just a bit curious.
I know John, you’d never do that.
Now kind of the next one for me and if this is asked, I apologize. But if a customer called today and said hey, I need a [inaudible], I want you to bring it back, realistically what's the time from today when that makes it to the field?
What’s the what, I'm sorry. John, can you repeat that?
Like bringing a cold stacked rig back, just the realistic timeframe to having that out?
I haven’t checked on that lately John, but I think generally speaking, you know we've got a couple of weeks to pull people together; probably four to five weeks in general to get everything ready. Six months ago it was probably two weeks and you know 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, but so…
Got it. Fair enough and the last one for me and this can be a guide answer, but 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, 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.
What about inquires?
Exactly, inquires have yeah…
That I don’t have on the table.
You know, yeah – pretty similar. I don’t have it in front of us, but I think it’s pretty similar John.
Okay. Well, can you [inaudible] and hope you guys – hope I’ll see you in a few weeks.
Yeah, looking forward to it. See you John.
Our next question comes from Derek Podhaizer from Barclays. Your line is open.
Hey! Good morning guys! I just want to go back to the daily margin conversation. The fiscal 2Q guidance margins look to stay kind of in the flattish range excluding reactivation expenses. Can you talk about where you see them going into fiscal second half ’22. The level of expansion driven by both the revenue size 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 as it relates – you know that cost range you just mentioned. I think the start, we will see as I mentioned the full effect of the labor increase hit us this quarter. And thankfully we are starting to see some stabilization as I mentioned for 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 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 opportunities we have 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 need it to be to get to the right return or the return gets to our cost of capital is a hurdle rate and above it, that's where we have to be as a corporation and that's where the upside could come from though the year. John, anything to add to that?
Yeah, I don’t really have anything.
Well, do you think you can get to a margin with a non-handle, in the second half ’22?
Well, I think…
Excluding reactivation. Sorry, excluding reactivation.
Yeah, well that's part of it, 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 flattened out slightly up, then obviously the rig recommissioning costs go away and your focusing – you know your costs are down, so you are focusing on growing the marching through pricing.
Thanks. That’s helpful, thank you. Switching over to sort of more kind of the new energy theme, geo thermal obviously the new source wasn’t picking up there. I know you guys had a few equity investments helping out 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 1000 megawatts requirement for geo thermal on the grid. Just any updates there, kind of how those pilot projects are developing?
Sure. Well I'll let Mark talk about some of those developments, some of the investments. I will say that we do have a rig working today, drilling a geo thermal wells in Nevada and it's drilling a couple of horizontal wells and a vertical well and I think its first horizontal geo thermal well in the U.S. that’s been drilled. So we are excited about that and seeing some opportunities there. Mark do you want to talk about that?
Sure. You know Derek, as it relates, we are always looking at making financial and operational decisions for the long term interest of the shareholders, and with regard to geothermal, we are 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 its 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. We recently invested in two separate geothermal companies. One is pursuing a closed loop concept that uses horizontal multilateral world wellbores, the other is pursuing the enhanced geothermal system concept using horizontal drilling. It’s just discussed and I mean you know the collective investments to-date is about $12 million, you know add to that that further in our pipeline we are 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 participated in some geothermal conferences and look forward to doing some more of that. We're making prudent and appropriate investments we think with the right sort of levels and that includes also any kind of services as well, so more to come.
Great, exciting stuff. Thank you.
Thank you.
The next question comes from Waqar Syed from ATB Capital.
Thanks for taking my question. John, first of all congratulations on a great sustainability to quarter. It really sets a new standard for sustainability reporting, so my congratulations to you and your team.
Thank you. They worked really hard on it. I’m proud of them.
Great, great. Yeah. Now my question is on the greenhouse gas emissions. We are hearing typically from the service industry is that the greenhouse gas emissions from the equipment and services at the well site go into the infantry off the E&P Company of the customer. You've taken a slightly different approach to that. Could you maybe elaborate the approach that you took and why?
Yeah well, I’ll handle that one. For us to come out and say, ‘hey! You know all our emissions are somebody else's problem.’ I don't think that from a credibility standpoint, I don’t think that will sit well with investors. So we are able to determine what our rigs emit towards emissions and so we're just being transparent that this is what we've been able to track over the past few years. We do that so there is a shared accountability there, but we want to be - have a full transparency and create some trust in the market by (a) we are shying away from this challenge and we're going to meet it head on.
Great! Your guys screen very well on our A2B 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 fist half weighted.
Yeah, 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’re really seeing 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 up-tick in activity.
But obviously you know it’s hard to say past year. 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 budget 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 really any insight into the private company besides just conversations that we have going on.
But hard to say at this point, our hope of course is that we'll see some additional growth along with pricing improvement 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.
Yeah, it's a really tight market, Waqar. There are just a very small number of rigs that have worked in the industry over the – less than two years a period of time, like you know in other words, rigs that were working prior to pandemic. So there is a large investment to be had. So I just think with the amount of activity that we have and I’m taking primarily about the super specs space, I think we are close to 70% utilization, but you know again the rigs 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.
Thank you very much. I appreciate you taking my questions.
Thanks Waqar.
And 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 said, we think we're very well positioned for the future. 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 and have a wonderful day!