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Helmerich and Payne Inc
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Good day, everyone, and welcome to the Fiscal Fourth Quarter 2019 Earnings Conference Call. All participants are in a listen-only mode. Later, you will have a chance to ask questions during the Q&A. Please note, today’s call will be recorded, and I will be standing by if you should need any assistance.
It is now my pleasure to turn the program over to Dave Wilson, Director of Investor Relations. Please go ahead, sir.
Thank you, Miranda, and welcome everyone to Helmerich & Payne’s conference call and webcast for the fourth quarter and fiscal year ended 2019. With us today are John Lindsay, President and CEO; and Mark Smith, 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 on current information and management's expectations as of this date and are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q and our other SEC filings. You should not place any undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements.
We will also be making references to certain non-GAAP financial measures such as segment operating income and operating statistics. You will find the GAAP reconciliation comments and calculations in yesterday's press release.
With all that said, I'll turn the call over to John Lindsay.
Thank you, Dave, and good morning everyone. The Wall Street Journal had two salient articles about the energy business this week. Both underscored the copious amount of energy supplies that exist worldwide and the Catch-22 this has created for the industry, our industry, the industry, most responsible for this economic bounty. Today, oil and gas companies are suffering from a curse of abundance, and according to the journal articles, we're still deep in the woods in terms of supplies and pricing. One article points out that energy has been the only negative sector in the S&P 500 over the past 12 months and that energy indices have declined by more than 40% during the year. This is an odd place to find ourselves as an industry, particularly after delivering so much value to the economy over the last decade.
The U.S. is no longer energy dependent. Our country is exporting energy again. Energy supplies and pricing remain key determinants of national security and the health of our economy, and while we may be considered an ugly duckling in Wall Street indices, only the energy industry can say with complete confidence that all other industries depend on us for their continued prosperity. Think about everything that abundant and low-cost energy enables across the globe. H&P is very proud to play a role in this progress and to have pioneered rigs and technologies that have enabled safer, faster, and better drilling than anyone could have ever imagined even 10 years ago.
I'm going to cover three main topics today: first is U.S. land activity and pricing; second is discussing updates and outlook for H&P Technology segment; and third, I will talk about our International segment. I'll begin with U.S. Land. The company continued to perform efficiently this past quarter despite a sizable pullback in industry activity. Collectively, our customers appear to have outspent their budgets during the first six months of 2019 and have been making up for it in the second half. Reflective of these trends as well as customer conversations, we expect to see more stability in rig demand over the next couple of months and heading into calendar 2020.
That said, capital discipline will remain the dominant theme. One silver lining to the spending discipline is that customers are becoming more selective in the quality and capability of the rigs they employ. Legacy rigs drilling unconventional wells declined approximately 45%, a significantly more pronounced drop when compared to the decline felt in the super-spec space, which is approximately 11% year to date. In previous industry downdrafts, we've experienced rigs released regardless of performance or capability. So this discernment on rig performance is welcome news and we expect this environment represents the final curtain for many legacy rigs in the U.S. market.
Despite the decline in industry rig count during 2019, super-spec utilization is still strong in the most active basins and as a company, we have remained disciplined in our approach to pricing. We believe services and solutions that deliver lower costs and better well performance deserve compensation that is commensurate to the value they add.
Our people, armed with our technology solutions, are partnering with our customers to drill safer, faster, lower cost and better wells, and they're making it happen every day. We have been experimenting with different pricing models, and thus far performance-based pricing models are getting the most acceptance. The KPIs are well aligned and focused on results that matter to the customer and can produce a win-win for both the customer and H&P. Shifting to our H&P Technologies segment, the fourth quarter results not only reflect the decrease in overall drilling activity, but also the slow and often difficult process of introducing change into the industry.
H&P Technologies’ purpose is to drive deployment or to drive development of an autonomous drilling platform designed to improve safety, drilling consistency and accuracy, and improving overall economics for our customers' wells. One example of this is AutoSlide, which is automated sliding while directional drilling, and it is currently commercialized in four U.S. basins. We have autonomously drilled over 100 wells and a total of 1.7 million feet of vertical, curved, and lateral footage. The customers that are using AutoSlide today love the results and are seeing consistent improvement and predictable performance that only automation can provide. We are working closely with our partners to close the gap in top tier performance in sustainable and scalable ways with AutoSlide. Our customers are seeing improvements in wellbore quality and the ability to lower the risk and cost profile through the enablement of head count reduction at the rig site. Even with the adoption, we've had thus far with AutoSlide, like in many disruptive innovations, the largest barrier to new technology adoption as the human workflow changes these technologies trigger. The adoption resistance we are experiencing today is reminiscent of the initial responses we had over 15 years ago when we rolled out our first AC-drive FlexRigs.
Based upon past experience introducing new technologies, we believe customers will continue to adopt and utilize these software solutions at a faster pace because of the value proposition they provide. Look at the headlines regarding parent-child well interference and the inherent consequences, and our MagVAR software solution can mitigate those risks. Today, MagVAR is on approximately 220 rigs and MOTIVE is on approximately 25 rigs including the AutoSlide commitments. These incremental investments in well performance, wellbore quality and productivity on the front end will pay dividends over the entire life of the well for our customers, not just drilling costs, but also by lowering costs for completion and production operations, and we will talk more about those metrics in the future. So, we'll be talking about it then.
Finally, I will conclude with our International business segment where last quarter we reported on some encouraging developments. I'm pleased to report this traction has continued into our fourth quarter and fiscal first quarter. The Company signed letters of intent to deploy a third FlexRig in Bahrain, two FlexRigs in Abu Dhabi, a high horsepower AC drive rig in Colombia, and our FlexApps to a customer in Argentina. Each of these successes demonstrate efforts to increase awareness in international markets of the value H&P Drilling and H&P Technologies can deliver from both the rig and a digital technology perspective.
The elections are over in Argentina, but their impact is still very uncertain. While we have not experienced any meaningful operational disruptions this quarter, we did have a customer delay a commitment to move a second super-spec FlexRig from the US. Even with these challenges, we continue to remain committed and optimistic about the ultimate potential in the Vaca Muerta basin and Argentina in general. In my opening remarks, I commented about the negative views on the energy business. Next year, we will celebrate our centennial, so we have seen our share of market challenges through the cycles. Delivering high levels of performance in a challenging environment is not new at H&P.
The dedication of our employees, combined with our rig fleet, digital technology solutions and customer partnerships are unmatched in the industry and give us a solid base to build and innovate upon.
And now, I will turn the call over to Mark Smith.
Thanks, John. Today, I will review our fiscal fourth quarter and full year 2019 operating results, provide guidance for the first quarter and full fiscal year 2020 and comment on our financial position. Let us start with highlights for the recently completed fourth quarter and fiscal year ended September 30, 2019. The Company generated quarterly revenues of $649 million versus $688 million in the previous quarter, totaling $2.8 billion for fiscal 2019 versus $2.5 billion in fiscal 2018. The quarterly decrease in revenue sequentially is primarily due to the expected decline in the average number of rigs working in the U.S. Land segment.
Direct operating costs decreased to $432 million for the fourth quarter versus $445 million for the previous quarter in correlation with the decline in our activity. General and administrative expenses totaled $50 million for the fourth quarter and $194 million for the full fiscal year, consistent with our previous guidance on the July call. Because our pre-tax income came in lower than we expected, we recognized a tax benefit for the quarter of $13 million as we had over accumulated our tax provision during the first nine months of fiscal 2019, relative to our actual year-end results.
To summarize this quarter's results, Helmerich & Payne earned $0.37 per diluted share, including the aforementioned tax benefits of approximately $0.12 per share versus a loss of $1.42 in the previous quarter. Activity this quarter came in below our expectations with highlights by segment as follows. One, U.S. Land costs were adversely impacted by a one-time legal settlement. Further, the rig count exited the quarter at the low end of our guidance range. Two, International earnings were affected by foreign exchange losses in Argentina as well as higher than expected start-up costs for our first international super-spec rig. Three, offshore experienced a 22-day downtime event on one rig for unplanned maintenance. And four, HP Technologies costs benefited from the reversal of a contingent earn-out liability which resulted in a net credit for expense for the quarter. However, our HPT revenue targets were not achieved, largely due to the rig activity volatility during the quarter.
I will discuss these segment results in more detail later in prepared comments.
For the full fiscal 2019 as a whole, we incurred a loss of $0.34 per diluted share. This was driven largely by the $224 million non-cash impairment announced in our third quarter as well as other select items including the mark-to-market losses on our legacy securities portfolio due to our adoption of a new GAAP accounting standard at the beginning of fiscal 2019. Collectively, these select items constitute a loss of $2.09 per diluted share and absent these items, fiscal 2019 adjusted earnings were $1.75 per diluted share. Capital expenditures for fiscal 2019 totaled $458 million, significantly below our previous guidance due to a combination of ongoing capital efficiency efforts as well as the timing of a small amount of supply chain spending crossing into fiscal 2020.
H&P generated $856 million in operating cash flow during the fiscal 2019, representing an increase of approximately $300 million from $558 million in fiscal 2018.
Turning to our four segments, beginning with the U.S. Land segment. We exited the fourth fiscal quarter with 194 contracted rigs, a sequential decrease of approximately 9% quarter end to quarter end and at the low end of our guidance range. H&P's U.S. land market share increased to 22% from quarter-to-quarter, as less capable legacy industry rigs were sidelined. As John mentioned, we expect more stability in the active rig count during this first fiscal quarter. Despite softening market conditions during the fourth fiscal quarter, pricing remained relatively firm in the super-spec market space. Our average rig revenue per day, excluding early termination revenue, decreased to $25,365 for the quarter, slightly under our guidance midpoint. The decrease as I mentioned in the press release, is mainly due to less FlexServices revenue, which is comprised of services including trucking, casing running and rental equipment among others. As a reminder from our July call, this figure excludes our FlexApp offerings, which are now included in our HP Technologies segment. The average rig expense per day increased to $15,440, due in large part to a charge of $9.5 million for settlement of a legal matter, approximating $500 per day.
Absent this charge, adjusted average rig expense per day increased to $14,934, which is above our previously guided range, due to volatility and maintenance and supplies cost, and in part to costs related to idling of assets.
Looking ahead to the first quarter of fiscal 2020 for U.S. Land, we exited the last quarter with 194 rigs working, but are seeing some slowing of net rig releases and a more stabilization in what has been a volatile market. Our public customers spend about 54% of their budgets during the first half of the calendar year and released rigs on a net basis in calendar Q3. As customers are reaching spending run rates that realign them with their budget goals, we have seen better equilibrium between rig releases and rig commitments.
We are currently operating a 190 rigs in the U.S. with an estimation that we will exit the quarter with between 187 to a 197 active rigs. This would result in a sequential decrease of approximately 6% in the quarterly number of revenue days which translates to an active rig count of approximately 191 rigs during the first fiscal quarter. A recent sampling of our customers suggests a decrease from their calendar 2019 CapEx budgets and our budgeting assumes calendar year 2020 activity levels, relatively flat from second half calendar 2019, which is in line with such a decrease.
We generally expect customer budget spin rates during 2020 to be more evenly distributed throughout the year. As the market tightens and as opportunities to displace legacy rigs arise, our initial objective is to put the 53 idle super-spec rigs we currently have back to work. Still, we have 44 FlexRigs that are upgradable to super-spec capability when and if market conditions warrant that investment.
Compared to the fourth quarter at $25,365 per day, we expect the adjusted average rig revenue per day to be within a range from $24,750 to $25,250. Our average day rate in both the spot and term markets remains in the low to mid-20s range and leading edge super-spec FlexRig pricing is also in the low to mid-20s.
The normalized average rig expense per day directly related to rigs working in the U.S. Land segment is now approximately $13,900, up roughly $200 from previous, as fixed overhead costs are spread across fewer working rig days. The average rig expense per day is expected to be in a range of $14,400 to $14,800 for the first fiscal quarter. Some of these costs are related to the idling of recently released rigs.
If and when rig count stabilizes, the significant costs we incurred in 2019 to re-commission long idled rigs and or stack out active rigs will subside and we can continue to incur decommissioning costs for Flex4 rigs as discussed last quarter as well as costs associated with maintaining the idle portion of the fleet.
We had an average of 133 active rigs under term contracts during the fourth quarter and today that number is 127 or about 67% of our 190 working rigs. We expect to have an average of 130 rigs under term contract in the fiscal first quarter, earning the current average day rates. 95 rigs currently remain under term contract through fiscal 2020.
Moving on to our International Land segment. The number of quarterly revenue days increased 6% in the fourth fiscal quarter in line with our guidance. The adjusted average rig margin per day in the segment decreased by $2,423 to $5,481 in the fourth fiscal quarter. This decrease was primarily due to higher-than-expected start-up reactivation cost for a super-spec rig in Argentina as well as macroeconomic circumstances in Argentina that are driving rate concessions.
Additionally, included in segment operating income was a $3.5 million currency exchange loss, driven by the significant decline in the Argentine peso. As we look toward the first quarter of fiscal 2020 for International, quarterly revenue days are expected to decrease slightly with an average fourth quarter rig count of approximately 17 -- excuse me -- fourth quarter rig count of approximately 17 active rigs in the segment.
Our first international super-spec FlexRig commenced operations in Argentina midway through the quarter with an international oil company. The average rig margin is expected to decline to between $3,000 to $4,000 per day during the first fiscal quarter, due to the start-up costs for two rigs in Abu Dhabi, one rig in Bahrain and one rig in Colombia. These four rigs are expected to commence operations late in the first fiscal quarter or early in our fiscal second quarter. Additionally, two rigs in Argentina will be rolling off of their original five-year term contracts with a national oil company during our first fiscal quarter. As customers gain clarity following the Argentina elections, we are hopeful that these rigs will return to work in the coming quarters in the Vaca Muerta.
Turning to our Offshore Operations segment, we continued with six active rigs during the fourth fiscal quarter and had one rig incur 22 days of unexpected maintenance downtime at zero rate, which negatively impacted revenues as well as expenses in the quarter. The average rig margin per day decreased sequentially due to the previously mentioned unplanned downtime.
As we look toward the first quarter of fiscal 2020 for our Offshore segment, we currently have six of our eight offshore rigs contracted. One rig recently commenced the process of changing customers during this quarter. The average rig margin per day is expected to increase to a range of $12,000 to $13,000 during the first quarter.
Now, looking at our Helmerich & Payne Technologies segment. Allow me to remind you once again that we removed our FlexApps -- moved our FlexApps to H&P Technologies in the fourth quarter. Historical segment information in the press release was recast to reflect the move of the FlexApps to have comparable financial information. Some customers have expressed interest in using the apps on non-H&P rigs in much the same way that the MOTIVE Bit Guidance System and MagVAR are deployed via software-as-a-service.
We are still working on the process to make our software applications available on other rig operating systems. HPT revenues fell short of expectations, primarily as a result of the drop in H&P's rig count and the overall rig count reducing the possible points of sale for these technologies. Currently, we are primarily focused on our AutoSlide technology offering and its adoption by customers on our FlexRig fleet. HPT operating revenue was about $14 million and operating expenses were netted to zero dollars due to a one-time credit.
The benefit was due to an $8.9 million reduction in the financial earn-out liability to metrics put in place at the time of an acquisition. Absent this benefit, the HPT segment would have incurred an operating loss of just over $8 million during the fourth fiscal quarter. We are expecting that fiscal Q1 revenue for HPT will be between $15 million to $18 million inclusive of FlexApps.
That said, fourth quarter results should serve as a reminder that HPT is a new business model and even with the ongoing successes we are experiencing, widespread customer adoption is hard to predict with certainty in our industry and even more so under challenging market conditions.
Looking forward to the fiscal first quarter and full fiscal year 2020, at fiscal year end and as of today's call, our revenue backlog from our U.S. Land fleet was roughly $1 billion for rigs under term contract which contain early termination provisions. Capital expenditures for the full fiscal 2020 year are expected to range between $275 million to $300 million, based on our current outlook for fiscal 2020 which is approximately a 40% reduction to fiscal 2019 CapEx. This capital outlay is comprised of four buckets, two buckets are investments in our fleet for maintenance CapEx and for conversions of skidding pad capability to walking pad capability. As previously guided, we expect to average from $750,000 to $1 million per active rig with international and offshore rigs being higher than the average. Maintenance CapEx is expected to be in a range of 57% to 62% of fiscal 2020 CapEx. For customers with a need for walking rigs, we will convert certain rigs from skidding to walking pad capability for multi-year term contracts. Walking conversions are initially estimated to be between 11% to 15% of CapEx. The third bucket is made up of tubulars which has become a larger part of our capital spend for the longer lateral wells we drill. This spend is offset in large part from customer reimbursement for the replacement value of drill pipe that is damaged or lost in hole during drilling operations. Tubular spend for FY 2020 is expected to be in a range of 17% to 19% of CapEx. I should note here that in FY19, US land drill pipe reimbursement represented two-thirds of gross proceeds from asset sales. The fourth and final fiscal '20 CapEx bucket is made up of corporate items, including some significant information technology projects estimated to be approximately 10% of the 2020 budget. During fiscal 2020, the CapEx just described should be spent more ratably throughout the fiscal year. The total number of walking conversions we complete with our budgeted dollars will depend on customer demand. Depreciation for fiscal 2020 is expected to be approximately $540 million. This is approximately $20 million less than fiscal 2019, primarily due to the third quarter downsizing of the Flex4 rig fleet.
Our general and administrative expenses for the full 2019 fiscal year are expected to increase slightly to approximately $200 million. The increase is driven in part by our two fiscal 2019 Technology segment acquisitions and in part by our targeted investments in certain capabilities, including cybersecurity. Harkening back to John's commentary on the autonomous drilling platform, we are investing still in our enhanced technology and innovation capabilities through ongoing research and development efforts, which we expect to approximate $30 million in fiscal 2020. The statutory U.S. Federal income tax rate for our fiscal 2020 year end will be approximately 21%.
In addition to the U.S. statutory rate, we are expecting incremental state and foreign income taxes to impact our tax provision, resulting in an effective tax rate range of 25% to 30%.
Now, looking at our financial position. As you may recall, we conducted a debt exchange in December 2018 to move our H&P IDC subsidiary senior notes to the H&P Inc. parent level. A very small portion of the noteholders did not exchange and in Q4, we called those remaining IDC subsidiary notes reducing overall outstanding debt by approximately $13 million. Our stock portfolio is a legacy investment that we have not added to in many years and we continue to monitor this holding for appropriate monetization. As such, we sold our legacy investment in Valaris plc in the fourth quarter, for proceeds of approximately $12 million.
During the fourth 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. Our longstanding dividend remains our primary method for returning excess cash to our shareholders. Despite our IDC debt extinguishment, our share repurchase and a Technology segment acquisition, our cash on hand and short-term investments at September 30, were up approximately $20 million from the preceding quarter ended June 30 to a total of $401 million. Including our revolving credit facility availability, our liquidity was approximately $1.15 billion.
On November 13, we extended our revolving credit facility maturity date from 2023 to 2024. We do not currently expect to utilize this facility during fiscal 2020. Our debt-to-capital at quarter end was 11%, a best-in-class measurement amongst our peer group and we have no debt maturity until 2025.
Looking ahead in our planning horizon, our investments in the last couple of years in our fleet and drilling solutions technologies, coupled with a disciplined and centralized cost focus, position us well to generate cash flow and maintain our strong balance sheet. In fiscal 2020, we currently expect to accrete a modest amount to our cash on hand, after capital expenditures and after our dividends.
Our balance sheet strength, liquidity level, and term contract backlog provide H&P the flexibility to adapt to market conditions, take advantage of attractive opportunities and maintain our long practice of returning capital to shareholders through our dividend. That concludes our prepared comments for the fourth fiscal quarter. Let me now turn the call over to Miranda for questions.
[Operator Instructions]. And we'll take our first question of the today from Kurt Hallead with RBC. Please go ahead. Your line is open.
Appreciate the update, the insights and the outlook there, John and Mark. So John, for you, just in the context of your discussion about a stabilization in demand for rigs, the one thing that kind of grabbed my attention specifically was your commentary about an expectation on kind of a consistent level of activity throughout 2020 that could kind of replicate maybe the kind of second half averages of '19. Do you get a sense in your conversations with the client base John and what kind of underlying commodity price is that dictated by?
As you know, Kurt, the -- our customers in general haven't -- in a large scale way, haven't reported their budgets for 2020. So, we're making a couple of assumptions here, obviously. I do think that for the customers that we have heard from, it sounds like a very similar price deck to last year, $50 per barrel to $55 per barrel as they are setting their budgets. And so, I think that's the best estimate that we have right now. I do think, again, based on what we're seeing is that our rig count should flatten out, hopefully improve through the rest of this fiscal year. If you just look at average activity levels for 2019 and then you contrast it with where we're estimating the exit level of activity would be for this year going into next year, it appears that there could be an opportunity for picking some additional rigs at the beginning of the year. It's so hard to tell right now, and again customers in a large scale way have to set their budgets. So, we're just making an assumption on that for the most part.
And then, just in the context of just looking at the International cash margin, right. So first half of the year, the cash margin was roughly about $12,000 a day, obviously, dropped down to where it is here in the fiscal fourth quarter. As you get out and you get these rigs up and running, is it possible that at some point during 2020 that the average cash margin could get back to where it was during the first half of '19 or do we have to rethink that and kind of reset the baseline on International cash margins with these new contracts and the contract rollovers moving forward.
Kurt, thanks for the question. Yes, the four contracts, the LOIs we have, which are turning in the contracts are accretive certainly to our margins, and some of the items we've experienced this quarter are transitory. So, yes, we do expect those to return.
And do you think can they get back to first half of '19 levels?
It just really depends on the rollovers and our ability to redeploy them, but that's the plan.
Thank you. And we'll go next to Sean Meakim with JPMorgan. Please go ahead.
So, in the lower 48, low to mid-20s rates per day for both term and spot work, I think, is what you said in the prepared comments. Can you maybe just talk about the mix of spot versus term work and how that's been changing in recent months, and then your outlook for both your customers' appetite for term as well as yours at current levels going into next year?
Sean, thanks for the question. We've been able to -- interestingly, we entered this calendar year at about 60% term coverage, and we're here today at 65% plus term coverage on the fleet; and as I mentioned, we're going to -- we already have booked for the full fiscal year 90 some odd rigs on term. We like that future certainty of cash flow and plan to keep a mix and a balance, and that mix has not changed for us through the year. The target is to keep it there.
Also, your comments on technology adoption, I think, are well taken, particularly in the current environment. So given maybe timing is a bit out of your control to some degree, but could you give us a sense of what type of revenue base for HPT is required to get that business up to operating profitability.
Sean, I might start with just by reemphasizing. I think one of the advantages to enhancing adoption is success. Obviously, we've had quite a few rigs that have been released, both our rigs and competitor rigs that had -- have had the technology deployed. So that's hurt us on the activity side. I think one of the reasons why I wanted to talk about what customers are liking is they like the consistency, they like the predictable performance that automation can provide. While it is a challenge on the change management perspective, they see -- they're beginning to see kind of a light at the end of the tunnel so to speak. So, I do think that there's opportunities to continue to grow the autonomous platform. Do you want to...
And it's really -- as John was just alluding to, it's about the number of deployments we have. It's about how many customers and rigs we have signed up for software-as-a-service, because individually, each of the product offerings are very high margin. They're simply due to their nature of software-as-a-service businesses. So, once we can get a critical mass of units in production, we're very excited about the accretive possibilities of HPT.
So is there -- are there any other benchmarks around how to size that critical mass you can offer for us?
Not yet. Too early.
Thank you. And we'll go next to Tommy Moll with Stephens Inc. Please go ahead.
Wanted to start on leading-edge day rates for super-specs. It sounds like we're still in the low to mid-20s range which I think is likely more disciplined than what a lot of folks had feared going into earnings season. So, I was hoping you could comment on H&P's continued commitment to remain disciplined there on pricing, and then also something that might help clear up some of the confusion among investors, I think, is the difference in the all-in rate versus the base rate where there are a lot of different components that build up to the number that you actually report. So, anything you could do to help us understand the difference in those two data points would also be helpful? Thank you.
Sure, Tommy. I'll start with -- we like to look at the value proposition that we're providing our customer and our focus is there. We really believe strongly that it's a win-win situation for us and our customer because if you look at the results, what you see are improving well cycle times, you see improving cost of wells for customers. Those cost savings are not a function of drilling providers lowering the rates. The cost savings are a function of better productivity. And then, as we begin to layer on additional technologies, there's going to be even greater -- greater savings. So, I think it really comes down to as you think about how hard the rigs are working and the value that we're providing, we really can't afford to come off of pricing.
And again, it's one of those situations you continue to hear me talk about partnerships with customers and that's really a big part of that.
I'll just add Tommy to that, that our average rig revenue per day range that I mentioned for our expectation on top of that are the FlexServices I mentioned and those range everything from trucking to casing running tools, rental equipment, extra personnel, other adders and those can vary from $1,000 to $2,000 per day depending on the basin, the customer, the rig itself. So that is what you add on top of the low to mid-20s spot rate to get to the average revenue per day.
And then to shift to CapEx, you've identified the budget for next year, which is at the midpoint, slightly lower than what we had previously expected. So good to see continued capital discipline there. You also broke out the piece of the overall budget allocated for maintenance CapEx and obviously, there is a big range there, but does that expectation for maintenance contemplate a U.S. rig count flat, up or down versus where you think you'll end this first fiscal quarter.
Tommy I'll let you do the math and extrapolate full-year guidance.
We can tell you what we hope for, does that -- we hope it’s up.
The upper end of the range? Okay.
Well, we -- that's what we hope, but again that's -- I think you, like, Mark said, you have to do the math on it, but depends on what oil prices are. There's a lot of -- as you know, there's a lot of variability. It's hard look out just one quarter, much less a full year.
Well, maybe I could ask it a different way or a related question. To the extent you do see opportunities to add rigs next year, will there be any headwind on your cost line as those rigs go back to work.
Not, as much as if we were reactivating for example. We are activating a lot long idled rigs or rigs that we had upgraded to super-spec because as I mentioned on the call the fact is, we have 50 plus super-spec rigs currently idled and those are reasonably idle. So they're hot to warm in most all cases and would require a little additional cost to get back into the field on one hand. On the other hand, we certainly would have personnel costs related to re-hiring and training et cetera.
[Operator Instructions]. We'll take our next question from Marc Bianchi with Cowen. Please go ahead.
I guess just quickly on the spot market or kind of leading edge market commentary, you guys have been disciplined. You're talking about stability in the rig count. Would you anticipate that kind of the -- going forward now, you sort of see stability in that leading edge rate in the low to mid-20s? Is that how you would characterize it?
Well, Marc, it's hard to say. We obviously have pricing pressure which isn't unusual in our industry almost regardless of what the market is, but obviously an improving outlook makes it a little less challenging. And again, I think, for the most part, the drilling peers have maintained discipline. We haven't seen a lot of irrational pricing, particularly with larger players. So, I think in general, our goal would be to keep it in the range where we are. That's our goal. It's hard to say for sure. How it ends up turning out, we can tell you what we're trying to accomplish, and again, we continue to focus very, very much on the value proposition that we're providing and whether that's providing different type contracts related to performance-type contracts where you're setting KPIs for your performance. Again, that's a true win-win and we're up for that all day long.
Okay, thanks for that John. In terms of HPT, I just wanted to ask on the -- in the fiscal fourth, Mark, you mentioned the $8.9 million of benefit there. Is that -- was that benefit in gross profit? I'm just trying to think about what kind of the run rate gross profit margin is to work off of the revenue guidance that you gave in here for fiscal first?
Yes, it -- I mean, it -- netted all cost zero basically.
So the delta would just be at the $8.9 million back to the…
Thank you. We'll go next to Taylor Zurcher with Tudor Pickering & Holt. Please go ahead.
John you talked again about the new pricing models that you're exploring and it sounds like the performance-based model is the one that's having the most success thus far. Could you maybe frame for us how many rigs are utilizing that pricing model today? And then, with the results thus far, I mean, is the revenue per day you're generating with that sort of pricing model accretive to what you might generate in the spot market today.
I believe that the performance pricing has been accretive to what we would see in the spot market. My preference is not to talk about the numbers in terms of numbers of contracts that we have, but we have continued to see improvements in that. The numbers are higher this quarter than they were last quarter, but in general -- again, it's a true win-win because it puts skin in the game as if there isn't skin in the game already, but it does put additional skin in the game. So we're all in on that type of pricing model.
And then one question on capital allocation. Obviously, the dividend's still the priority moving forward. But this quarter, you did purchase, I think, about 1 million shares. Maybe you have some extra cash in the balance sheet moving forward and if the stock prices is still in and around current levels today, should we expect you guys to continue to whittle away at share repurchases over the next few months or few quarters?
We have a -- Taylor, we have a standing authorization to buy back 4 million shares per annum. Having said that, we have repurchased shares in the past, but not on a frequent basis at all. Based on the opportunity set or what to do with cash at the time and the amount of cash accretion we were -- we were experiencing in Q4, we felt the share repurchase was a prudent decision. It also serves to mitigate some of the dilutive effects of various stock related awards.
Thank you. And we'll go next to Scott Gruber with Citigroup. Please go ahead.
Can you update us on how many FlexRigs have walking systems today and do they still cost -- I think it was about $5 million per when we talked kind of this time last year. Is that still around the right cost or has that come down some?
From a -- I'll start off, Scott. From a cost perspective of the walking rigs with the higher end number they were to actually upgrade Flex3 to walking was about $9 million, whereas the skidding upgrade was $3 million. The cost to convert however, from skidding to walking is around $7 million is what we're projecting. So the delta there being the PSI and the third mud pump. Today in our fleet, we have -- and to the first part of your question, today, in our fleet, we have about 40 walking rigs.
So just to be clear when you guys say the budget, there is 11% to 15% skidding to walking conversions, that's the $7 million you're targeting associated with those conversions?
Yes. Otherwise, $4 million to $6 million for the year is the number you're trying to get to I think?
Yes. Got you. I mean, overall, are you seeing customers pay a premium for the walking FlexRigs over the skidding rigs or we just generally helping the appeal of the rigs to customers and adding utilization?
We have, Scott. We've had a -- we've seen a consistent more mid-20s type pricing. We've also had skid rigs at mid-20, but the average hasn't been mid-20 and I would say the average for the walking rigs have been closer to mid-20s. And in general, we've had two-year term contracts with those as well. Two-year to three-year, some cases, three-year term contracts.
And I'll just add to that we will require a term contract to do such a conversion.
Is it safe to say that the walking rigs are at the high end of the spot range and it's skidding rigs are towards the low end? Is that fair?
Yes. But we don't have that many that are on spot, most of them are termed up.
Thank you. And we'll go next to Thomas Curran with B. Riley FBR. Please go ahead.
John or Mark, when it comes to the new performance-based contracting model you've been experimenting with, what percentage of performance-based wells drilled or revenue generated to date has resulted in higher revenue per day than the day rate you otherwise would have earned under the traditional model or if it's a better measure of a higher average daily margin, whichever it is you think we should be focusing on to determine the efficacy of the new model?
Yes, I don't have a percentage top of my head, but I do know that the margins and the revenues are generally higher than what we would see in the spot market type of contract.
Could you give us an idea of average order of magnitude or sort of the greatest premium you've been able to realize thus far?
Yes. Our preference would be, we would rather not for competitive reasons, but again I think it's -- I think it's a great contract design. As I said earlier, we've got -- we've -- both parties have skin in the game and we're trying to provide a win-win.
Okay, but it sounds like you're definitely capturing that greater value you're delivering than you otherwise would have been and that's encouraging. Then for AutoSlide, I know there was an expectation that you have -- a first commercial deployment in the Delaware by the end of last quarter calendar 3Q. Would you please update us on that Delaware portion and then speak to which basins are most likely to be numbers six and seven and whichever order they might occur.
As far -- I don't -- I'm trying to think we're six and seven or -- and I don't recall where those are, but Delaware is just right around the corner. It's actually been on queued up for several months, but it really comes down to having the right customer, the right partnership as I've mentioned on several of the calls. The change management side of the equation is as important as anything that we're doing. The technology piece is really the easy part. It's the workflow changes and change management. So I think we will have the Delaware in this quarter if I'm not mistaken, we'll have our first round going there.
Which will be the fifth basin.
Yes, that will be the fifth basin.
And then just one more for me on AutoSlide. How many different unique customers have commercial used it thus far?
I think we're at five that we've been working with.
Thank you. And we can go next to Chase Mulvehill with Bank of America. Please go ahead.
Thanks for squeezing me in. So I guess, real quick -- I may have missed this, but did you disclose the average day rate for your term contracts for fiscal year 2020.
I don't know...
I'm sorry, could you say that again.
No. Yes, maybe I was working up. So, yes, so the -- looking to see if you disclosed the average revenue per day for U.S. Land business for the term contracts for fiscal year 2020. Typically, you give us that on the earnings calls.
I did. I said that they're earning the current average day rates.
Okay, got it. Current average day rates, okay. Can you clarify that for us? The current meaning of which you gave for the quarter for 4Q or for 3Q or for calendar 4Q?
Yes. It’s that low to mid-20 day rate. So if you take the question we had earlier about the average rig revenue per day, back of the FlexServices and you're right at that day rate.
Yes, I guess, I'll just take it offline, that's fine because there’s a big difference between low-to-mid. So, all right. I guess, from the day rate side, you've talked about some dayrate pressure. It seems like maybe some of the rig declines are slowing. Have you -- have day rates start going down at this point for the super-spec rigs?
As we said, we've been very fortunate to have pretty firm consistency in our low-mid, 20-day rates. So, yeah, we're pretty fortunate in that spot and term contracts seem to be at about the same level.
Yes, I was taking more leading edge. If I'm hearing you right, day rates -- leading edge day rates are flattened out and then stop going down if I heard you correctly.
I would say that.
Yes on the leading edge, I would agree with that.
I wanted a real quick one. Argentina, could you talk about what you expect in Argentina as we roll into 2020? I think you've got some contracts that rollover. How are negotiations going with those and should we expect those to kind of continue into 2020?
We do have, as I mentioned, the first two IPF rigs that were dispatched to Argentina five years ago are rolling off in this fiscal first quarter. And the rest will roll off through fiscal '20 and we have been in active discussions to put those rigs back to work with IOCs and other E&Ps in the Vaca Muerta. As John mentioned, we're sort of -- and I think I might have reiterated as well, we're sort of waiting for the dust to settle from the recent election cycle and -- but are pretty buoyed by a recent trip to the country and visiting with prospects and are still pretty bullish on the long-term prospects of the Vaca Muerta for Argentina and also for Helmerich & Payne.
Thank you. And at this time, I'd like to return the floor back to Mr. John Lindsay for any additional comments.
Okay. Thank you, Miranda. I'd like to close out the call today by reinforcing H&P has a track record of generating strong cash flow and maintaining a strong balance sheet in an industry where that is rare. This strength, along with our great team of employees put the company in a competitive position to address the challenges and opportunities that lay before us. We're going to continue to partner with customers to achieve mutual long-term success. So thank you again for your interest in H&P and have a great day.
Thank you. This will conclude today’s program. Thank you again for your participation. You may now disconnect and have wonderful days.