Good day everyone and welcome to today's program Fiscal First Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. Please note this call may be recorded. It is now my pleasure to turn the conference over to David Wilson, Director of Investor Relations. Please go ahead.

Thank you, and welcome everyone to Helmerich & Payne's conference call and webcast for the first quarter of fiscal 2020. With us today on the call are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. John and Mark will be sharing some comments with us, after which, we will open the call for questions. Before we begin our prepared remarks, I will 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 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 forward-looking statements. We also make reference 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 that said, I will now turn the call over to John Lindsay.

Thank you, and good morning, everyone. 2019 was a challenging year for the industry overall, but it's during these seasons when our industry comes together to create stronger partnerships and embrace new ways of thinking and innovation. This is what we are experiencing, and it can contribute to our results. Today, we will share some additional context about how H&P's leadership position and performance, both of which continue to improve because of the Company's ability to simultaneously deliver incremental value for customers, adapt to increasingly difficult market conditions, and advance the future of automation and drilling. This quarter's results reflect the momentum of shared successes with customers and the Company's ability to remain agile and focused on results from our customers and for H&P stakeholders. I'm going to begin talking about our experience with what we are seeing exploration and production companies' value drivers. Our customers are looking for every opportunity to invest optimally. They are seeking the best partner with the best expertise and experience that can transcend today's challenging market environment. We strive to align ourselves with the customers' objective to enhance economic returns through better performance and technology. We are working hard to put this shared focus and decision-making at the forefront of all of our partnerships. Our strategy is focused on strengthening all of our current customer relationships and building more along the way. We believe technology and automation will be the catalyst for value creation in upstream oil and gas operations. There is power in predictability through reliable and repeatable performance provided by process excellence and automation. And we are seeing that payoff for H&P and for our customers. This concerted effort will continue to set us apart, and I believe it is one of the reasons why we are gaining traction. We see significant value capture opportunities resulting from our autonomous drilling platform. For our customers, maturing basins and normalized well cycle times are drawing more attention to the advantages that wellbore quality delivers. Our automation solutions, specifically AutoSlide, which is automated sliding while directional drilling, have numerous points of differentiation from competing services in the market today. The primary and most customer-centric differentiation is our AutoSlide algorithms are tuned with wellbore economics and each customer’s value drivers in mind. Specifically, these algorithms optimize the trade-off between drilling days, time in the hydrocarbon zone and wellbore quality. As the industry continues to migrate to factory-like drilling, economically focused automation will be the key enabler. What we have found is this predictability allows for optimizations of other key drivers that positively impact the total life of the well. Examples are optimizing completions and providing an opportunity to push the envelope on new methods and techniques that ultimately lead to production increases and lower costs associated with completion. In addition to creating value for our customers through improved well economics, our technologies reduce the environmental impacts of drilling operations by creating more precise and safer ways to maximize extraction, thus, unlocking even more value with a smaller environmental footprint. Since 2017, we have made several digital technology acquisitions and have added significant expertise to our team to complete our digital technology strategy roadmap. The first step of that strategy is wellbore quality and economically focused automation with AutoSlide, and we plan to launch more levels of our autonomous platform during 2020. We believe we have the expertise and capabilities today to take the next step for our industry without further acquisitions. The power of process automation that drives predictability is paramount for the future of oil and gas. Last year, we introduced the need for new commercial models where we are focused on creating a win-win value capture for our customers and for H&P stakeholders. Given our customer’s focus on spending within budgets, optimizing investment and value, we are continuing to develop new pricing solutions to reflect the growing partnership between H&P and our customers. These solutions reinforce that approach, enabling us to share an equitable portion of the value we are delivering. Last quarter, we announced that new commercial contracts made up approximately 10% of our contract mix. During the first fiscal quarter, although today, we have approximately 15% of our active FlexRig fleet contracted under nontraditional day rate contracts, the majority of which are performance-based contracts. As Mark will discuss in more detail in his remarks, these performance-based contracts align H&P's performance and compensation with the customers’ goals and provide for a commensurate distribution of the incremental value creation. We are seeing momentum across our primary drilling business segments as U.S. land rig count fell during 2019, H&P's market share grew from approximately 22% to over 24%, indicating a growing preference for super-spec rigs and the performance these rigs deliver relative to legacy SCR rigs and lower performing AC rigs. Along with market share gains, our quarter-end rig count was sequentially higher than the previous quarter's ending rig count. We believe capital discipline by our customers will remain a prevailing thing and we expect industry activity to look similar to the average level experienced during the second half of calendar 2019, which implies a modest increase from current levels. As drilling performance continues to improve, a significant portion of these gains are attributable to the added capabilities and efficiencies from super-spec capacity rigs. An awful effect of this progress are higher daily maintenance costs and higher capital costs related to third mud capacity, 7,500 PSI capacity, multi-well pad capability, and more horsepower requirements, but that trade-off is well worth it. Our experience shows that over a three-year trend, the super-spec capacity of FlexRig can drill 15% to 20% more than non-super-spec rigs. Moreover, the super-spec FlexRig incorporates a number of enhancements that improve safety for employees and reduce the environmental impact at a drilling location. That said, in order to reflect continued efficiency and value gains for E&P revenues for rig services that provide optimized drilling solutions need to increase to cover the cost of increased maintenance and supply and capital costs, as well as returns that our shareholders demand. Mark will address the details of pricing more completely in his prepared remarks, but pricing remains firm for FlexRigs in U.S. land, and why shouldn't it? Super-spec utilization is strong, especially in the most active basins, and the rigs are delivering high levels of performance and value for customers. Before shifting to our international segment, another success during 2019 for H&P was growing our partnerships with major oil and gas companies. We have grown our FlexRig fleet market share to 16% from 6% at the beginning of 2019. And we believe the Company is best positioned to continue to grow our partnerships with the majors and IOCs. So let's shift to our international segment. This quarter also proved to be positive for our business outside of the U.S. We remain optimistic about the opportunities we are seeing in the Middle East, and we were pleased to put a rig back to work in Colombia. Other rigs in the Middle East are now fully utilized, and prospects for further growth in this region are encouraging and would likely result in the exporting of additional FlexRig drilling rigs from the U.S. to satisfy any demand. As we hear about unconventional resource plays in the Middle East and South America, our experience, our expertise and our technologies will continue to put us in a great position to grow in the future. So in closing, financial discipline and maintaining a strong balance sheet are hallmarks of the Company and set us apart from many industry peers. H&P has paid cash dividends to shareholders since 1960, and last year, we increased the annualized dividend per share for the 48th consecutive year. In thinking about culture and how that can set a company apart in an industry, we are in the midst of a momentous year at H&P. 2020 is our centennial year, and we are using some of this time to reflect on our history. So primarily, we are looking at our path forward. In keeping with this milestone, we will remain focused on maintaining our position as the industry's most trusted partner in drilling productivity and technological innovation. Our people have always been dedicated to helping our business through the ups and downs of our industry. And we know that our employees, combined with our rig fleet and technology solutions are the key to our continued long-term success.

Thanks, John. Today, I will review our fiscal first-quarter 2020 operating results, provide guidance for the second quarter, update full fiscal year 2020 guidance as appropriate, and comment on our financial position. Let us start with highlights for the recently completed first quarter. The Company generated quarterly revenues of $615 million versus $649 million in the previous quarter. The quarterly decrease in revenue is primarily due to a decrease in the average number of rigs working in the U.S. land segment as expected. Total operating costs incurred were $401 million for the first quarter versus $432 million for the previous quarter. The decrease is primarily attributable to the aforementioned activity decline. General and administrative expenses totaled $50 million for the first quarter in line with our expectations. Our Q1 effective tax rate was approximately 32%, which is slightly higher than our guided range due to a discrete tax expense. Summarizing the overall results of this quarter, H&P incurred a profit of $0.27 per diluted share versus earning a profit of $0.37 in the previous quarter. First quarter earnings per share were positively impacted by a net $0.14 per share of select items as highlighted in our press release. Absent the select items, adjusted diluted earnings per share were $0.13 in the first quarter versus an adjusted $0.38 during the fourth fiscal quarter. Capital expenditures for the first quarter of fiscal 2020 were $46 million; this amount is under our implied guided run rate due to the timing of various projects. Turning to our four segments, beginning with the U.S. land segment. We exited the first fiscal quarter with 195 contracted rigs, which was, as John mentioned, the first time since calendar year 2018 that we have seen a sequential increase in activity. H&P increased its U.S. land market share to 24% by quarter-end due to the continued sidelining of less capable legacy rigs in the industry. As John discussed, we expect to see a modest increase in rig count during the second fiscal quarter. Pricing remains firm in the super-spec market space during the first fiscal quarter; our average rig revenue per day excluding early termination revenue increased to $25,397 for the quarter, which was slightly above our guidance. As a reminder, from our November call, this figure excludes our FlexApps offerings, which are now included in our H&P Technology segment. Helmerich & Payne's average pricing per day varies from basin to basin due to both underlying hydrocarbon economics and competitive rig supply dynamics. Further, as John stated, our pricing is differentiated due to the unique value we deliver our customers as evidenced by our leading market share. In addition to the dynamics specific to each market, pricing variations are also driven by other variables including term coverage and customer concentration. Our current pricing remains in the low to mid-20s with an overall average around $23,000 per day. As a reminder, Flex services including trucking, casing, running, rental equipment, etc. are additive to day rate and are included in revenue per day of $25,397. As John discussed, our performance contracts are gaining ground, as a larger portion of the fleet is shifting to this commercial model. As H&P provides value to our customers, such as by reducing their overall well spread costs, H&P participates in that savings creation. These performance contracts are now generating approximately $500 per day more in margin than our average day rate and model margins produced. The average adjusted rig expense per day increased to $14,987; this is above our previously guided range, primarily due to higher-than-expected self-insured medical expenses incurred in the fourth calendar quarter, which is the final quarter of the medical plan year. Looking ahead to the second quarter of fiscal 2020 for U.S. land, we exited the first quarter with 195 rigs working and currently we have 197 rigs turning to the right. Customer conversations lead us to believe that there will be a decrease of approximately 10% in CapEx spend in calendar 2020 compared to calendar 2019 levels. This implies that the number of wells drilled in 2020 would decline by 2,300 from the 16,400 wells drilled during the calendar year 2019, an approximate 14% decrease. To close some of this gap, we would expect to see a modest accretion to the exiting rig count in the calendar year end. With that caveat, we are also anticipating that our customers will spend budgeted rig CapEx at a more even rate throughout this calendar year. Given that, we expect to exit the second quarter with between 193 and 203 active rigs. This would result in a modest sequential increase in the quarterly number of revenue days, which translates to an average rig count of approximately 196 rigs during the second quarter. As the market tightens and as opportunities to displace legacy rigs arise, our initial objective is to put the 45 idle super-spec rigs we currently have back to work. Also, we still have 44 FlexRigs that are upgradable to super-spec when and if market conditions warrant that investment. Compared to the first quarter at $25,397 per day, we expect the adjusted average rig revenue per day to be within a range from $25,000 to $25,500. 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 at that same level. The average rig expense per day is expected to be in a range of $14,650 to $15,150 for the second quarter. While our overall rig count has stabilized, we will continue to incur costs to re-commission idle rigs and/or stack out active rigs due to ordinary rig churn across basins. The per day cost here can vary considerably depending on the type of rig and the market dynamics in the basins where the activity is occurring. We will also continue to incur costs associated with maintaining now a portion of our fleet. At the start of this fiscal year, we elected to set up a wholly owned insurance captive to ensure the deductibles for our workers' compensation, general liability, and automobile liability insurance programs from October 1, 2019 forward. Our operating segments pay monthly premiums to the captive for the estimated losses based on external actuarial analyses. The result is a transfer of risk from our operating subsidiaries to the captive for the deductibles which is our self-insurance retention. We do not expect any significant changes in our ongoing segment per day expenses as a result of this shift. The insurance premiums are included in the operating segment expenses and are included in intersegment sales and the other non-reportable segment. These intercompany premium revenues and expenses are eliminated in consolidation. The actuarial estimated underwriting expenses for the three months ended December 31 was approximately $8.5 million and was recorded within the other operating expenses line item in our audited condensed consolidated statement of operations. We had an average of 129 active rigs under term contract during the first fiscal quarter and today that number remains 129 or about 65% of our 197 working rigs. We expect to have an average of 126 rigs under term contract and in the fiscal second quarter earning our current average day rate. 103 rigs currently remain under term contract through the last three quarters of fiscal 2020. Regarding our International Lands segment, the number of quarterly revenue days is relatively flat in the first fiscal quarter, slightly above our guidance. The adjusted average rig margin per day in the segment increased by $1,731 to $7,208 in the first fiscal quarter. The increase was primarily due to lower-than-anticipated cost associated with some of our rigs in Argentina among other factors. As we look toward the second quarter of fiscal 2020 for International, quarterly revenue days are expected to decrease approximately 7% with an average second quarter rig count of approximately 16 to 17 active rigs in the segment. We have been successful in redeploying all five of the rigs we currently have in the Middle East. And while these additions have not been incremental to our international rig count, they have served to mitigate the rigs that have rolled off contract in Argentina. We remain optimistic that there will be opportunities in Argentina to put rigs back to work. However, the timing is uncertain. The average rig margin is expected to decrease to a range of $6,000 to $7,000 per day during the second fiscal quarter, as decreasing startup costs in the Middle East are more than offset by the impact of the idling Argentina rigs rolling off of their five-year NFC contracts. Additionally, we incurred unplanned maintenance expenses during the startup phase of putting an idle rig back to work in Colombia. Turning to Offshore Operations segment. We averaged six platform rigs working in the first fiscal quarter. We exited the quarter with six contracted rigs. However, one rig has since then released and mobilized. The average rate margin per day increased sequentially due to the unexpected maintenance downtime incurred in the previous quarter. As we look toward the second quarter of fiscal 2020 for the Offshore Segment, we currently have five of our right offshore rigs contracted. One of those five rigs is in the shipyard, as it transitions from one Gulf of Mexico customer to another and is expected to recommence drilling operations in late March. The average rig margin per day is expected to decrease to a range of $10,000 to $11,000 during the second quarter due to the reduced activity. Finally, looking at our H&P Technology segment, HPT revenues were largely in line with our expectations. HPT operating income was approximately $2 million when excluding research and development costs of $6 million. We expect Q2 revenue HPT to be between $16 million to $19 million inclusive of FlexApps. As our teams leverage recent successes, we expect continued growth in customer adoption during a stable to modestly increasing rig count environment. In December 2019, we closed on the sale of TerraVici Drilling Solutions Inc, resulting in a gain on sale of approximately $15 million. As a reminder, we wrote off the intangibles related to TerraVici in the fourth fiscal quarter of 2018. Now let me look forward on corporate items for the second fiscal quarter and the remainder of this fiscal year. At December year-end, and as of today's call, our revenue backlog from our U.S. Land segment was roughly $900 million for rigs under term contract with early termination provisions. Capital expenditures for the full fiscal 2020 year are still expected to range between $275 million to $300 million based on our current outlook for fiscal 2020, which as a reminder is approximately a 40% reduction to 2019 CapEx. We expected $46 million in the first quarter, which is less than the implied quarterly run rate of our guidance due to timing differences of procurement activities and project progression. As we mentioned in the press release, assets sales are primarily customer reimbursements for the replacement value of drill pipe that is damaged or lost in hole during drilling operations. These sales offset a large portion of our tubular purchase bucket of CapEx. Our previously communicated expectations for full fiscal 2020 general and administrative expenses, research and development expenses, depreciation and effective tax rates are unchanged. Now, looking at our financial position, Helmerich & Payne had cash and short-term investments of approximately $412 million at December 31, versus $401 million as of September 31, 2019. We earned cash flow from operations of approximately $112 million in fiscal Q1. The sequential decrease in cash flow was due to some of our conversion factors including reduced activity, annual payment of accrued short-term incentive compensation plan, seasonal holiday slowdown of receivable collections, and the payment of the legal settlement that was accrued and disclosed in the previous quarter. We expect cash flows from operations to be higher in the remaining quarters of our fiscal year. Our debt-to-capital at quarter end is 11%, which is a continued best-in-class measurement among our peer group. A reminder we have no debt maturing until 2025. Our expectations for the remainder of fiscal 2020 include operating activity levels and pricing to generate sufficient free cash flow to cover our selling general and administrative expenses, debt service costs, planned capital expenditures, and current dividends while modestly accreting our cash on hand. 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 first fiscal quarter. Let me now turn the call over to Nikki for questions.

We will take our first question from Jacob Lundberg from Credit Suisse. Your line is open.

Hey, good morning guys.

Good morning.

Just to start off, I wanted to drill down on the performance-based contracts that you mentioned. Could you just help us think about how quickly that mix can grow as a percent of your total work? You had a nice increase in fiscal 1Q. Do you anticipate that to continue? And then anything you could provide in terms of your desired mix of traditional versus performance-based would be helpful.

Okay. Jacob, this is John. It is hard to know for sure how we can impact the mix. What I do feel positive about is that we are taking a customer-centric approach to these new commercial models. You know, every customer looks at things, looks at costs, looks at their particular program a little bit differently. So we are trying to align it with what their drivers are. Most of these contracts have been performance-based contracts, so there is a true win-win for both the customer and H&P in this case. So our hope is that we will be able to continue to do more of that. One way to think about it is most of the rigs that have the potential of entering into these types of contracts are generally in the spot market rigs, as opposed to those that are already under term contract. But again, I think there is an opportunity for us to do more. As you said, we had a nice improvement. Our sales team continues to adapt to this. We have made lots of investments in the organization to create the infrastructure that we need to manage these types of contracts. So again, our hope is to continue to grow it. As far as the total mix, again, that is hard to say as well. But, I suspect that as we get more mature and our customers see the benefits that we will be able to enter into more of those.

And do you have a desired mix? Would you go pure performance base if the market was there or would you like to maintain some portion of the fleet still on the traditional structure?

Well, I think, you know, Mark had mentioned it in his remarks that our average revenue is higher on our performance-based contracts. Obviously, we are taking some associated risk when you do that. You know, again, it is hard to say what kind of a mix in terms of total, but we are definitely interested in doing more. I think the likelihood, the reality of it, at least anytime soon to have the whole fleet on performance or some other type of commercial model besides day rate probably isn't achievable, realistically.

Okay. And then a follow-up if I could, on the performance-based contracts. Could you just talk about the spread? So if on average you are seeing $500 a day more on the performance-based contracts, what does that spread look like? Presumably there are some jobs that don't go your way, and maybe it is even a negative impact I would imagine there is somewhere it is significantly more positive than $500, and maybe what does that spread look like? And then over time, where do you think you can bring that total average incremental day rate on those contracts?

Yes, that is a tough one. You are accurate in that we are not going to achieve, if you are talking about performance contract, you are not going to achieve it every time. Obviously, the goal is, at the end of the day, to be able to have a higher revenue than what we would achieve with a day rate contract. So, we are still in the early stages, even though we have been at this for a year. Our industry in some respects moves pretty slow on things like this. I really want to stress that it is a partnership with our customer. You are only going to be able to have these sorts of arrangements types of contracts with customers if you have a pretty good relationship with and are able to negotiate something that again is a true win-win for both parties.

Do you think it would be fair to say that over time there is an ability to increase the $500 number though?

I would sure hope so. I mean, we have examples where at several thousand dollars, obviously, you do have those that don't work your way for one reason or another. But again, we are an organization that has a lot of data, a lot of information. I think that we can continue to help our customers to drill wells more effectively.

Alright. I appreciate it. Great quarter guys. Thank you.

Thank you.

We will take our next question from Tommy Moll from Steven Inc. Your line is open.

Good morning, and thanks for taking my questions.

Sure, Tommy.

So, wanted to start on H&P Technology, specifically AutoSlide, which it looks like is now on six basins. In a macro environment as you indicated you expect for this year and maybe slight uptake in rig count, but continuing capital discipline among customers. How do you feel about the adoption going forward for AutoSlide? Are we still in the early days where the adoption rates slow? Or do you feel like we are getting closer to an inflection point?

Well, Tommy, I think we have had a nice improvement in adoption since September 30. Our AutoSlide rig count is at 15 today. I think we were around seven. So we have more than doubled since September 30. So we have had some nice adoption. There is, I think in some respects, because of capital discipline and there are some adverse effects I think that you end up dealing with on the adoption side, and then the other side is just as we have said before, it is a pretty significant change in workflow at the rig site. So there is a real need for change management. But over the last several months we have obviously achieved a lot of success. And as you said, we are in six basins today, they are the most active basins and we are having some success. So we are getting some adoptions. So our expectation is that we continue to grow. We would love to be a layout for you. What our ultimate - while we are being eight successive quarters. But so much of that really depends on how quickly customers can adapt to the AutoSlide situation and that we are changing the workflow and we are demanding in most cases. I think 60% or 70% of the AutoSlide jobs we have today are fully de-manned as far as the directional driller not being on the rig, which is a great thing. It is a great thing for the customer. It is a great thing for the industry because of the reliability piece, less exposure, but it is disruptive.

Thank you, John. And just sticking with the technology theme, you mentioned in your remarks that there could be more announcements coming in 2020 on the autonomous drilling theme. I expect we will have to wait for some press releases to get the full details on any of those, but could you give us even just high level some of the different pieces of the drilling process that you think are right for disruption with some autonomous solutions?

I think what I prefer to do, Tommy, is wait and roll it out with greater clarity in what I would be able to give you right now. But the fact is there are some things that are done at the rig site that are highly people-oriented obviously. And there is a lot of variability in the performance because of the human interaction. There are things that are right for automation, they are right for developing algorithms to replace that and to add a more factory-like outcome. So, there will be more to come on that. I wish I could tell you exactly when that is. But, I think in the next quarter or two, we will be able to have another commercial announcement that we will roll out nicely with AutoSlide.

Okay. We'll stay tuned for the updates and I will turn it back. Thank you.

Alright. Thanks, Tommy.

We will take our next question Sean Meakim with JP Morgan. Please go ahead.

Thanks. Hi, good morning.

Good morning, Sean.

Good morning.

Can we talk about the change in quarterly profitability for H&P Technologies and how you would be guiding investors going forward? I guess I'm trying to think about the buckets that are driving the change, is it just absorption of higher volumes, R&D is separated? Are there mixed considerations? Just trying to think about, how to understand the fundamentals, it is just going to be probably a little bit tough to navigate that quarter-over-quarter?

Thanks, Sean. There are several moving parts in there, and because of that, we are going to keep our guidance for the near-term really at a top revenue line item. To your point, there is increased adoption of some products, especially the new AutoSlide product that John has been speaking of this morning. You also have some price accretion on a per unit basis as we work with different contracting models. AutoSlide, importantly, is not on a day rate model. We have various forms of contract. As we move through some of these early days, we will probably land on the best few forms of contract that are mutually beneficial to the customer and ourselves. So, until we get to that point, it is really a sort of a top-line guidance. Obviously, we have much more discreet internal goals, but those are moving as well as we learn more through this process.

That is very helpful. Are you able to give us any hindsight color on the prior quarter relative to the one before that?

Not at this stage, Sean. Not at this stage.

Okay. Fair enough. Maybe. So switching to international, could you maybe just give us a sense of what you see as an opportunity set in terms of the number of rigs that could be exported from the U.S. over whatever timeframes you are comfortable with, next 12 months or something? And just curious how those latest contract terms are looking relative to prior between Latin America and the Middle East?

Well, as John mentioned, we are excited to put a rig back to work in Colombia and we continue to have marketing discussions in that country. We still, on a long-term basis, are excited about the unconventional play in Argentina and are being patient there as our customers are while we sort through the new dynamics in that country. But, we do have rigs rolling off of the original YPF five-year contracts through the rest of this calendar year, and we had been in and continue to be in discussions with IOCs and other players related to the redeployment of those rigs. As it relates to the Middle East, I would be a bit more cautious, if you will, in trying to provide any specific guidance. We have numerous discussions that are happening in various countries in the Middle East and are very excited about being able to participate in unconventional plays as they begin to really take shape at scale in some countries there. So, excited to be participating in discussions, those range from preliminary discussions all the way through to Tinder-type discussions. And it is early days, but we have 45 idle super-specs in the United States that are great candidates to put to some of those opportunities when they come to fruition.

So you wouldn't be able to characterize changes in rates or term at high level across any of those markets?

Not yet. No. The FlexRigs we think can really add value in the Middle East. And we also have some HPT trials happening with some of the HPT Technology products as we speak there as well. And who knows, as we have discussed in previous calls, the Technology could be a rig pull through.

Right. Okay. Thanks a lot.

Thanks, Sean.

Our next question comes from Marc Bianchi from Cowen. Your line is open.

Thank you. Just following up to the question on HPT and profitability. I appreciate that you don't want to give us any guidance, but if I just kind of assume what we had in the most recent quarters, $10 million bucks of gross profit and that I take U.S. Land and International and offshore all at the midpoints of your guidance. I kind of get $210 million of gross profit. I'm wondering what else we need to deduct from that to get to your EBITDA? Because we have got this insurance thing this quarter that is a new item and then obviously G&A and perhaps R&D from there.

There are several things built into your question there, Marc. As it relates to the - first of all, let me just address the insurance captive. From a segment operating expense perspective there is no change there. It is just transferring of those premiums to the captive. Again, it is intersegment revenue to the captive, which is eliminated in consolidation. And it is a big self-insurance retention and deductible. And so we are managing that retention a bit differently through the captive. But from a segment expense perspective, really no change. As it relates to HPT?

Sorry, go ahead. Mark, can I just clarify that just because you are on it on the insurance piece. So of that 210 of gross profit, that is all in the segments. There is no additional deduction that I would need to make to that to get to your EBITDA as it relates to the insurance.

You can see that in the segment reconciliation, which is in the press release and will be in the 10-Q filed later today.

And Marc, we can walk you through the kind of the reconciliation offline.

Yes, I think it is good to talk about it live, cause I'm getting a lot of questions about it. So perhaps other investors are very interested. Mark, you were going to talk about the G&A and the R&D.

Yes, the G&A. I think we have all the components to get to your EBITDA number, Marc really, but specific to your HPT question in particular on any more details within there. We have a growing revenue base, as we have said before we are excited about it because the technology is really software and service. So in these initial deployments, we are really getting started. We have a bit of variable operating expenditures, but through time, we expect that to be a really margin- accretive portion of the business, as we have talked about. The G&A related to HPT in particular is pretty fixed and the R&D is as well. As I mentioned in my opening comments, we don't have any changes to the full-year guidance. Once we get through the technology roadmap that John has articulated, we will through time have R&D drop-off obviously. And once you move to a sort of maintenance, if you will, on the software, so you go from version to version as opposed to new software. But that is a bit out in our planning horizon. So, if you stick with the numbers we mentioned in November for yearly G&A and R&D et cetera, you will be able to get to your EBITDA.

Got it. Got it. That is great, Mark. Thanks. And then just if I could on kind of M&A, I caught the comment that you don't need to do any more M&A to build out the automation capability, but you did make the comment in the press release about having kind of ample flexibility to take advantage of additional investment opportunities. So I'm just curious, you know, what that might be referring to and help maybe set some expectations for M&A for us.

Well, Marc. From an M&A perspective, you have heard in the past what we don't plan to do, which is any consolidation in the industry, as far as rigs go. I think the investments that we will be making are on the technology side, there is obviously the potential to grow internationally, as Mark mentioned, continuing to enhance the fleet based upon customer demands and that is where we are going to be investing.

Got it. Okay. Thanks very much. I will turn it back.

Thanks, Marc.

Our next question comes from David Anderson with Barclays. Your line is open.

So, John, we are talking about AutoSlide and how to improve your performance, also talking about contracts. So I'm just wondering how the two work together on kind of the 15% of your business, which is these new commercial models. Are you employing AutoSlide in any of those contracts yet?

You know, there had been some overlap in bids that we have made. I can't speak to any particular right now that we have. But it is definitely in the discussion. To your point, I think it does make a lot of sense as we grow the AutoSlide functionality and automation in general. I think there is that potential there.

And then, also we just talked a little bit about the customer mix. I'm just kind of curious of that 15%. Is that more skewed towards the bigger operators? I'm just curious which types of customers are more receptive to that, because I also certainly noted how you talk about your share of the majors had gone up. I'm wondering if those are related.

Really the answer to the first part of your question is we have interest and have contracts right now with large and small E&Ps, and I expect that that is going to continue. These performance contracts are not related to the growth on the major side of the equation. But I wouldn't rule it out longer-term. I mean, let's face it, the majors are very much value-oriented and I think as they look at ways to enhance value, not only time-based value but overall lifecycle of the well value. I think we have a lot of opportunity to grow there. So, hopefully that gives us some opportunity going forward.

Yes, I would certainly think so. I just wonder if you could just elaborate a little bit about the growth opportunity in the Middle East. I think the last time I saw, a couple of rigs operating in Bahrain and a couple of rigs idle in UAE. Could you just tell us how you said we have five rigs operating at Middle East today? Could you just talk a little bit about where those are? It looks like you are reactivating in UAE. We just saw an announcement came out about a big unconventional play in UAE, which I wonder if that is related. And also if you wouldn't mind just also just telling us are you qualified in all the major GCC countries in the Middle East, particularly Saudi? I don't remember you ever working in Saudi, just wondering if you are qualified there?

I will just start it off with the five that you mentioned specifically. I think if you went back a year ago at this time we had one rig working in Bahrain, two idle there and two idle in Abu Dhabi. Interestingly last year we closed our Ecuador operation because of its subscale size and we really have the same size operations in Bahrain and Abu Dhabi that we purposely kept those open as marketing venues, sensing what could be a developing unconventional play in several countries there. And that is coming to fruition; all five of those rigs are now working; we continue to have prospective customers going to visit them as well. And yes, that is exciting opportunities in many countries there including the UAE.

What about Saudi? Are you qualified there?

We do have an entity in Saudi Arabia, a legal entity I should say. And we have the entities at various countries actually in the Middle East.

Our next question comes from Scott Gruber with Citigroup. Your line is open.

Yes. Good morning.

Good morning, Scott.

Question on working capital for Mark. So working capital it sounds like it should improve going forward. Do you have any color for us on whether working capital will be a benefit or a cash drag for H&P for the full-year?

It should improve, as I mentioned in the comments. I think we are going to be relatively stable activity level. So I think working capital will be relatively stable as well as opposed to being a big benefit or drag honestly. Having said that, we at H&P are still trying to turn over every rock we can and we had some successful working capital projects last fiscal year. And this year we have more that we are looking at including an assessment of our inventory levels.

Got it and just back on the U.S. Land, do you think your rate premium appears in U.S. Land has widened and not just relative to the smaller players, but even relative to some of your bigger, like on primary competitors? You think your rate premium has actually widened a bit there?

Scott, I know our other drilling peers, at least I don't believe they have reported yet. I don't have the details of the data to know if it has widened. I think in general we have had pricing discipline in our sector. As I have mentioned, the rigs are performing at a high level and adding a lot of value. And so, I think in general it is in everyone's best interest to continue to keep pricing at reasonable levels or today's levels. And again, I think there is an argument to be made that because of the cost side of the equation and rigs working harder, that there is an element for increasing revenues in order to cover those expenses.

Got it. That is it for me. Thank you. Thanks for the color.

Thanks, Scott.

Thanks.

We will take our next question from Chase Mulvelhill with Bank of America. Your line is open.

Hey. Thanks for squeezing me in. I wanted to come back to the performance base of the new commercial models that you are pushing out to the market. So, if we kind of do some back of the envelope math, it kind of looks like you may be saving $15,000 to $20,000 per well. Could you kind of walk through the different pieces of cost savings that you are saving for your customer? How much of it is you are drilling faster versus kind of taking people off or maybe cannibalizing some of the other drilling services? So, just kind of help us understand the different buckets for the value proposition to your customer.

Chase, I would say most of the shared savings are related to time, and as you look at a real simple example is a 15-day well and two days of savings, and a total spread rate of $150,000 total between those two days, and then you essentially share those savings. So, let's say you split the savings. So, on a 15-day well, you have got $5,000 a day type of additional revenue. I'm trying to give you a simple example. There are other KPI-type models as well, where customers want to focus on specific items during the course of the well. I don't have all those at the tip of my tongue right now. But most of those are areas that they are having challenges and/or there is an opportunity for us to come in and perform at a higher level than what our peer would be doing and we are able to do that by essentially going in with a little bit lower rate and then earning a higher rate.

Got it. Okay. A quick follow-up just on the performance-based contracts. If we think about how you are trying to attack the risk side? If you think about what kind of risks you are absorbing on the third-party service providers, how do you protect yourself there? And then also, you know, with performance-based contracts, it always seems like a perpetual kind of resetting of the baseline as performance continues to improve. So how do you protect yourself on that element as well?

Well, that is a very good question. You have obviously seen these types of contracts over time and there can be some negative results as a result of either resetting framework or the third parties. I think as we look at our experience and expertise and the data set that we have, you know, we have a pretty good handle on obviously the customer that we are working with, the partnership that we share have a pretty good understanding of those areas that are particularly or have been particularly a problem in the past. And obviously one of those is the directional drilling component. We obviously have significant expertise in directional drilling, internally with the directional drillers and then obviously AutoSlide algorithms. So, lots of data at our fingertips that we didn't previously have before. So I think it helps us actually work with our customers to even potentially high-grade some of the third parties that are working jointly with us on location. So overall, I'm not overly concerned or bothered by the third-party piece of the equation. Obviously the reset that you mentioned is just something that you have to work out in the contract. But again, as I think about our industry and how we have really changed and improved over time in that we are working together more as partners with our customers. And I think that obviously they want us to win because if we win they win. Right. And so there is an opportunity for both parties to come out in a better place.

Awesome. Good to hear that your customers are willing to work with you. Alright. Thanks, John.

Alright, Chase. Thank you.

And I will now turn the program back to John Lindsay for any closing remarks.

Alright, thank you and thanks to everyone for joining us on the call today. We really appreciate it. We are looking forward to celebrating our Centennial during 2020, as I said earlier, but what we are really doing is looking ahead to our bright future, looking forward to that. And, thank you all and have a great day.

This concludes today's conference. You may disconnect your line. Have a good day.