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Edited Transcript of HP earnings conference call or presentation 16-Nov-18 4:00pm GMT

Q4 2018 Helmerich and Payne Inc Earnings Call

TULSA Nov 17, 2018 (Thomson StreetEvents) -- Edited Transcript of Helmerich and Payne Inc earnings conference call or presentation Friday, November 16, 2018 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Dave Wilson

Helmerich & Payne, Inc. - Director of IR

* John W. Lindsay

Helmerich & Payne, Inc. - President, CEO & Director

* Mark W. Smith

Helmerich & Payne, Inc. - VP, CFO & CAO

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Conference Call Participants

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* Bradley Philip Handler

Jefferies LLC, Research Division - MD & Senior Equity Research Analyst

* Byron Keith Pope

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Oil Service Research

* Jeffrey Leon Campbell

Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services

* Kurt Kevin Hallead

RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst

* Scott Andrew Gruber

Citigroup Inc, Research Division - Director and Senior Analyst

* Thomas Allen Moll

Stephens Inc., Research Division - Research Analyst

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Presentation

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Operator [1]

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Good day, everyone, and welcome to Helmerich & Payne Fourth Quarter Earnings Conference Call. (Operator Instructions) Please note this call may be recorded. (Operator Instructions)

It is now my pleasure to turn the program over to Mr. Dave Wilson, Director of Investor Relations. Please go ahead, sir.

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Dave Wilson, Helmerich & Payne, Inc. - Director of IR [2]

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Thank you, Erika, and welcome everyone to Helmerich & Payne's conference call and webcast for the fourth quarter and fiscal year ended 2018. With us today are John Lindsay, President and CEO; and Mark Smith, Vice President and CFO.

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 or our quarterly reports on Form 10-Q and other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these looking statements.

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

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

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [3]

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Thank you, Dave. Good morning, everyone, and thank you again for joining us on our fourth fiscal quarter earnings call. H&P's leadership position and super-spec rigs contributed to another strong quarter of operational results. We expect to see additional demand for our company's super-spec FlexRigs heading into our new fiscal year, particularly as customers push lateral lengths, pad drilling and an industry trend toward greater well complexity.

In addition, our new lines of digital technology-based solutions gained further traction during the quarter as more customers realize the value these solutions provide.

I will focus my remarks on 5 main areas this morning. First, we believe the super-spec rig market in U.S. land is fully utilized, and we still see indications that additional demand will continue, even as oil prices have moved lower. This robust demand is supportive of the increased pricing environment, and we are persistent in our pursuit of higher dayrates as a result of the value proposition we deliver to our customers. We upgraded and converted 54 FlexRigs to super-spec during fiscal 2018. This brought the total number of super-spec FlexRig rigs in our U.S. land fleet to 207 at the close of the fiscal year, and we believe we have over 40% of the active industry super-specced rigs. As stated earlier, we are seeing further demand for these rigs and expect to maintain an average upgrade or conversion cadence of 12 rigs per quarter for the next few quarters. Currently, we have the first and second fiscal 2019 quarters fully committed at this cadence, and there are already a few commitments in the third fiscal quarter. The average length of term for these contracts is over 2 years in duration, and rates are in the mid-$20,000 per day range. The incremental investment in these upgrades generates a good return for our shareholders and enhances the overall value of the H&P fleet by enabling the technology offerings we have developed.

Second, we have long articulated the benefits of our uniform FlexRig fleet designs from the vantage point of safety, operations, supply chain and efficiency. Now with the rollout of our FlexApp solutions during the latter half of fiscal 2018, we have further capitalized on this design benefit by expanding the use of our uniform fleet as a standardized digital platform. FlexApps are software-based applications that can be layered on top of our drilling control systems to improve reliability and performance, increasing the value proposition of H&P's family of solutions. FlexApps solutions are a separate revenue stream from the rig dayrate and are designed to provide a substantive value addition to the customer via the FlexRig digital platform. By reducing human variability, FlexApps enhance efficiency by automating our drillers' tasks and decisions, resulting in improved life of downhole drilling tools, fewer bit trips as well as better drilling performance and overall reliability for the customer. We have several case studies that demonstrate considerable savings and improved reliability for customers through the use of our FlexApps solutions.

For my third point, I want to mention our new software technology subsidiaries that are focused on wellbore quality and wellbore placement. MOTIVE Drilling Technologies and MagVAR continue to gain momentum with customers, both on FlexRigs as well as other competitor rigs. The MOTIVE Bit Guidance Software System provides a higher-quality wellbore, and MagVAR provides MWD survey correction services to improve wellbore placement. Both subsidiaries are drilling activity as the industry continues to drill longer laterals on multi-well pads with tighter well spacing on those pads. These trends are compiling more operators to acknowledge the benefits of adopting these technologies, and we believe demand is close to reaching a tipping point. To date, the adoption of MOTIVE technology has provided bit guidance on nearly 10 million feet of hole, and it is currently operating on approximately 30 rigs. MagVAR is currently on approximately 270 rigs, up from 180 rigs in December 2017 at the time of the acquisition and continues to grow activity in the survey correction market. As the industry continues to move into a manufacturing drilling mode, the standardization of directional drilling processes through digital approaches allows greater repeatability and transparency of execution, which brings tremendous value to the customer. Combining these disruptive technologies with our uniform digital FlexRig platform, we are in initial customer beta testing of AutoSlide, our new automated directional drilling sliding solution that we announced in September. AutoSlide takes an evolutionary step in drilling automation by eliminating human intervention during slide operations for all sections of a horizontal well. The results have been promising for adding greater reliability and performance to the customer. AutoSlide is a crucial step toward dramatically increasing quality and the repeatability of a critical operation that is typically performed by a third-party human directional driller. Our beta testing has already resulted in higher-quality slides with less time required for sliding, which delivers faster overall performance in the vertical, the curve and the lateral. We hope to be commercial in the Midland Basin during the first calendar quarter of 2019. AutoSlide is an important step in our autonomous drilling platform. As we look to the future, we expect an ongoing trend to more complex well trajectories, more tightly controlled well spacing and longer lateral lengths and the resulting demand for enhanced control of wellbore placement and quality. Therefore, we are optimistic about MOTIVE and MagVAR technologies and believe they will enhance the current state of directional drilling execution and hold the promise of providing significant value to the customer.

Now shifting to the fourth topic, concerning commercial models. In order for H&P and the other oil field services companies that are able to demonstrate value creation through new technologies, through super-spec upgrades and through automation strategies, we must develop new pricing solutions that allow us to make a reasonable rate of return, so we can continue to make these value-adding investments. A case in point. During fiscal 2018, as compared to 2014, our FlexRig fleet drilling performance delivered nearly the same amount of footage, approximately 75 million feet of wellbore, with an average of 65 fewer working rigs. The average FlexRig in 2018 drilled approximately 65,000 more feet of hole, which is about a 25% increase, than the average FlexRig in 2014. And the asset test of value to the customer, this increased drilling efficiency per rig delivered over one additional well per year, including about 2,500 feet of additional wellbore per well. We recognize that our company isn't responsible for all of that performance enhancement, but it is clear to us that the current dayrate model is not adequately compensating us for the additional value being derived in well cost savings and productivity. We are pursuing new pricing models for FlexRigs, for FlexApps, MOTIVE and MagVAR, which includes performance-based contracts, revenue per foot, lump sum and other models are under consideration.

Finally, before turning the call over to Mark, it's important to understand our views for rig activity related to the oil price outlook. Our 2019 budget was set in October, at a time when oil prices were $10 to $15 a barrel higher than they are today. However, oil prices today are still higher than the average price expected by E&Ps preparing for the 2018 budgeting cycle last year. Consequently, what we are hearing from customers today hasn't changed over the past few months in terms of activity going forward for the remainder of calendar year 2018 and into the first quarter of 2019. Our term contract book is strong with approximately 60% of the currently active fleet on term and our upgrade cadence of approximately 12 rigs per quarter committed through March of 2019. H&P has about 50% of the upgradable AC drive fleet, which gives us the ability to upgrade more effectively than our peers. It's also important to recognize that even with softer oil prices, approximately 28% of the active industry fleet drilling horizontal wells today are legacy rigs and aren't as efficient, safe and reliable as the other 72% of the active industry rigs that represent the AC drive technology fleet. So while our super-spec rigs are geared towards operators who are drilling longer laterals, we have started to see some interest from customer discussions targeting FlexRig4s for our E&P programs that don't require super-spec capacity. Our Flex4s provide a high level of value, offered at a lower price point than a super-spec FlexRig, allowing us to compete head-to-head with legacy rigs and when there's less technically challenging work as a result of the value proposition delivered.

So we are looking forward to a strong 2019. I believe all of our areas, U.S. land, offshore, international and our technology subsidiaries are positioned well heading into the new year. So now I'll turn the call over to Mark.

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [4]

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Thanks, John. Today, I will review our fiscal fourth quarter and full year 2018 operating results, provide guidance for the first quarter and full fiscal year 2019 and comment on our financial position.

Let's start with highlights for the recently completed fourth quarter and fiscal year ended September 2018. The company generated quarterly revenues of $697 million versus $649 million in the previous quarter, totaling $2.5 billion for the fiscal year. The quarterly increase in revenue is primarily due to both the increase in revenue days and average quarterly revenue per day in the U.S. land segment. Direct operating cost remained relatively flat at $449 million for the fourth quarter versus $445 million for the previous quarter. Our impairment charge of $23 million incurred in Q4 consisted of certain equipment due to the wind down of Ecuador operations, the write-down to scrap value of our previously decommissioned rigs and the impairment of goodwill related to our TerraVici business line.

General and administrative expenses totaled $53 million for the fourth quarter and $200 million for the fiscal year, in line with our previous guidance on the July call. Our income tax provision from continuing operations for the fourth quarter includes discrete tax items of approximately $13.5 million related to state and international jurisdictions where we operate.

Concluding this quarter's results, Helmerich & Payne earned $0.02 per diluted share versus a loss of $0.08 in the previous quarter. The fourth quarter was adversely impacted by $0.17 per share of select items as highlighted in our press release. Absent these items, the adjusted diluted earnings per share were $0.19 in the fourth quarter versus an adjusted loss of $0.01 during the third fiscal quarter. Earnings totaled $4.37 per diluted share for the full fiscal year 2018, of which select items accounted for $4.24 per diluted share. This $4.24 is comprised primarily of a noncash gain related to a reduction of H&P's deferred income tax liability as a result of applying the new corporate tax rate enacted by the Tax Cuts and Jobs Act of 2017. After the select items, fiscal 2018 adjusted earnings for the full year were $0.13 per diluted share.

Capital expenditures for fiscal 2018 totaled $467 million, above our previous guidance, due largely to the completion of more super-spec upgrades than anticipated.

Now turning to our 3 segments, beginning with the U.S. land segment. We exited the fourth fiscal quarter with 232 contracted rigs and had an increase of approximately 4% in the number of active rigs quarter-to-quarter, achieving a current 21% U.S. land market share. We experienced a growth in activity throughout the fourth quarter, and we expect to see a similar increase through the end of the first quarter of fiscal 2019. Since the last earnings call on July 26, 2018, our activity has increased by 11 rigs. The Eagle Ford led the way in Q4 with an 8-rig increase to 45 active rigs.

The fourth quarter's favorable market conditions continued to allow pricing improvements. Excluding early termination revenue, our average rig revenue per day increased to $24,321 for the quarter. The average rig expense per day decreased to $14,109 due in part to the timing of favorable adjustments to certain self-insurance expenses. Looking ahead to the first quarter of fiscal 2019 for U.S. land, we expect a sequential increase of approximately 4% to 5% in the quarterly number of revenue days, representing an average rig count of approximately 239 rigs. Compared to the fourth quarter, at approximately $24,300 per day, we expect the adjusted average rig revenue per day to increase to a range from $24,500 to $25,000. The expected increase is driven by market dynamics due to the tight market share for super-specced rigs across numerous basins.

We are also encouraged to see the customer response to our FlexApp offering that John mentioned earlier. The midpoint of the average rig expense per day is expected to remain consistent with our prior guidance and be in a range of $14,500 to $14,900 per day, absent onetime benefits related to self-insurance expense adjustments that affected fourth quarter. The normalized average rig expense per day directly related to rigs working in the U.S. land segment remains approximately $13,700. This per day estimate excludes the impact of expenses directly related to inactive rigs and the upfront reactivation expenses related to rigs that have been idle for a significant amount of time. We had an average of 135 active rigs under term contracts during the fourth quarter. And today, 148 of our 238 contracted rigs are under term contracts. All but 21 were priced in the post-downturn market. We expect to have an average of 141 rigs under term contract in the first fiscal quarter, earning an average margin of $11,000 per day. For the 114 rigs we already have under term contracts in 2019, we expect average margins to approach $12,000. For the 42 rigs currently under term contract in fiscal 2020, the associated margin is approaching $13,000.

Turning to our offshore operations segment. We continued with 6 active rigs during the fourth fiscal quarter. The average margin per day increased sequentially due to the absence of onetime costs that were incurred in the prior quarter. As we look toward the first fiscal quarter of 2019 for the offshore segment, we currently have 6 of our 8 offshore rigs contracted. One of these rigs is undergoing approximately 30 days of planned maintenance during the quarter. The average rig margin per day offshore is expected to be $8,500 to $11,000 during the first quarter.

Regarding our international land segment, as expected, the number of quarterly revenue days increased slightly in the fourth quarter by approximately 3%. The average rig margin per day in the segment decreased by $1,336 to $8,658 in the third quarter. This decrease was due to onetime cost of approximately $2 million associated with our wind down of Ecuadorian operations. We have not had any activity in Ecuador since January 2016, and the country has had only a modest recovery since 2014, with less than 10 rigs working. This limited scale opportunity drove our decision to focus on other international markets in our planning horizon.

As we look at the first quarter of fiscal 2019 for international, we expect to end the first quarter with 18 to 19 active rigs in this segment. As a reminder, we believe we have the leading market share in Argentina with over 20% of the active rig count and closer to 40% as it relates to unconventional drilling. The average rig margin per day is expected to be flat at approximately $8,000 to $9,000 during the first quarter. We also expect to incur some final wind down expenses for Ecuador in the first quarter.

Now let me look forward for the fiscal first quarter and full fiscal year 2019. At fiscal year-end, our revenue backlog from our U.S. land fleet was roughly $1.1 billion for rigs under term contract, which we define as rig contracts with original fixed terms of greater than 6 months and that contain early termination provisions. As the contracting market has remained strong, our current revenue backlog for the U.S. land fleet as of today's call is approximately $1.4 billion, representing an increase of $300 million since September 30.

Capital expenditures for the full fiscal 2019 year are expected to range between $650 million to $680 million based on market expectations as of today, which are markedly different than the planning environment this time last year. This investment in our fleet is comprised of 3 distinct buckets. Given our current customer commitments going into the third quarter of fiscal 2019, bucket 1 contains capital expenditures to upgrade and convert FlexRigs to super-spec capacity. This organic growth and fleet high-grade opportunity is estimated to range between $260 million to $275 million and represents the largest portion of our 2019 CapEx plan. The second bucket is estimated to range between $195 million and $240 million and consists of FlexRig capital maintenance. Such capital maintenance averages between $750,000 to $1 million per active rig. The third bucket of 2019 CapEx will range from $165 million to $195 million is comprised of 2 items: a, a catch-up bulk spare equipment purchase for the scale of our growing super-spec fleet. For example, at the 2014 peak, our working rigs had 2 pumps on average, whereas today our fleet averages nearly 3 pumps. Similarly in 2014, the typical rigs' tubular component was 18,000 feet, whereas today's lateral wells have driven the typical tubular footage per rig to 22,000 feet and higher. And b, rig reactivation cost, which have increased as the average idle time of reactivated rigs is now close to 4 years of stacking.

During fiscal 2019, the CapEx I outlined is expected to be weighted to the first 3 quarters as we take advantage of our differentiated ability to respond to the current demand for super-spec rigs through our reactivation and upgrade programs. We are currently planning to upgrade a higher percentage of the walking rigs in the 2019 program versus skidding systems. Therefore, the average upgrade cost per rig will be higher compared to last year, reminding that the average skid system is approximately $3 million and the average walking package is approximately $8 million. The total number of upgrades that we complete with our budgeted dollars will depend on market demand and our final mix of skidding versus walking pad capability.

Depreciation for fiscal 2019 is expected to be approximately $560 million plus an additional $30 million or so in abandonments and accelerated depreciations that are primarily related to super-spec FlexRig upgrades. The total of $590 million is approximately $5 million more than fiscal 2018. Our general and administrative expenses for the full fiscal year 2019 are expected to be flat from '18 at approximately $200 million. We will leverage our capabilities in Tulsa that were expanded in fiscal 2018 to support our growing rig fleet, with a goal to reduce certain field expenses.

Following our acquisitions of MOTIVE and MagVAR, we expect to experience growth of their respective services to an expanding customer base and a rig count. Parqueting back to John's commentary on AutoSlide, we are investing in our enhanced technology and innovation capabilities through increased research and development efforts, which we expect to total between $25 million to $30 million in fiscal 2019.

The statutory U.S. federal income tax rate for our fiscal 2019 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 2019 tax rate range of between 28% to 32%.

Now looking at our financial position. Helmerich & Payne had cash on hand of approximately $284 million at September 30, 2018 and short-term investments of $42 million. Including our revolving credit facility availability, our liquidity was approximately $587 million. On November 13, 2018, we extended and expanded our revolving credit facility to $750 million, enhancing our liquidity by an additional $450 million and extended our maturity date to 2023. While we do not currently expect to utilize this facility during fiscal 2019, it is a prudent step, given our current operating scale and the nature of our industry.

Our debt to capital at quarter-end was 10%, a best-in-class measurement amongst our peer group. We have no debt maturity until 2025.

Opportunistic reinvestment in our FlexRig fleet continues to strengthen the asset base while increasing market share. Our U.S. land market share at the 2014 peak was 15% and has grown to 21% today. Our balance sheet strength, liquidity level and term contract backlog provide H&P the flexibility to pursue planned reactivation and upgrade programs, develop and deploy differentiating technology and return on capital to shareholders through our very long standing dividend. In fiscal 2019, we will consume a portion of our cash on hand. As stated, we do not expect to have to utilize our credit facility availability.

Looking ahead in our planning horizon, the investment in our fleet and drilling solutions technologies, coupled with a disciplined and centralized cost focus, will yield expanding positive free cash flows. That concludes our prepared comments for the fourth fiscal quarter. Let me now turn the call over to Erika for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) We'll go first to Byron Pope from Tudor, Pickering, Holt.

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Byron Keith Pope, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Oil Service Research [2]

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John, I have a question for you. I mean, it seems as though the super-specced rigs are quickly becoming the standard in the U.S. land rig market, much as -- much in the way that Helmerich & Payne led the way for AC drive rigs to become the industry standard and realize that you guys collect tons of data coming off your rig in your Center of Excellence. And so my question is, could you give some qualitative color around the extent to which the horizontal wells you're drilling for your customers today are making super-specced rigs must haves as opposed to nice to haves? I mean, the fact that you have visibility well into the spring of the next year with regards to upgrades you just had, again, they're -- these types of rigs are becoming must haves. So just looking for some qualitative color there.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [3]

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Sure, Byron. One of the things that you've heard us mention probably over the last year or better is the last thing we want to do is overbuild the super-spec fleet -- the capacity of the super-spec market. So one of the things that we have done is we had continue to monitor on a quarterly basis the super-spec rigs that we have and are they actually doing super-spec work. And pretty consistently, quarter-to-quarter, we've seen anywhere from 85% to 90% of the wells that we're drilling actually require the capacities that a super-specced rig has. And so I think that's a pretty good measure of demand. So the -- a couple of other primary components are related to the depth of the well, the length of the lateral, whether the rig is doing pad drilling work or single well work and what kind of pressure that's required for the mud system -- the mud pumps to be able to effectively pump and the amount of setback capacity, all those sorts of things. So to answer your question, we are still seeing demand clearly by the amount of backlog that we have and the commitments we have through March.

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Byron Keith Pope, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Oil Service Research [4]

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That's helpful. And then just a second very quick question. With regard to the different commercial models that you touched on, I'm assuming that the baseline today is most, if not all, of your FlexRigs are on the standard dayrate type of model. But how do you see the emergence of these different commercial models unfolding over the next couple of years?

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [5]

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Yes. It's a great point. As I've thought through -- you go back to when we very first started building FlexRigs, when we -- when the market figured it out and we were able to really create some adoption with customers, and if you remember, we weren't building any new rigs unless we had a 3-year term contract that would provide a reasonable rate of return and in excess of our cost of capital and getting 85%, 90% of our money back in the term of the contract. And that was -- while it had been done previously in our industry, it wasn't -- I don't think it was done nearly in as widespreaded way. And so I think that's where we are today. You just look at the performance metrics that I talked about, we were at 65 fewer rigs in 2018 and effectively drilled the same amount of footage. And so the great news is we are providing great value for our customers. And so our expectation is, and like we did when we started the FlexRig program, is we're going to have customers that are partners in this. We have very, very strong partners that we -- that -- customers that we work with that have been partners for a long period of time. The fact of the matter is, what used to be a 20-day well or a 30-day well is now a 20-day well or a 20-day well sometimes is a 15- or a 10-day well. And so we, obviously, on a revenue basis, are making less and less. So I don't have -- we don't have all of the models figured out. But what we do know is that today, we do have a small mix of entering into different pricing models, whether it's performance, whether it's a lump sum or other types of contracts. And so we're going to continue to look at that. And as we trend -- as we progress to the next year or 2, I think we'll start to see a mix shift away from just the dayrate model.

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Operator [6]

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We'll go next to the line of Tommy Moll from Stephens.

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Thomas Allen Moll, Stephens Inc., Research Division - Research Analyst [7]

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John, you indicated there is continued upward pressure on dayrates, given the full utilization in the super-spec market and characterized leading edge for an upgrade is still somewhere in the mid-20s. Going forward, do you think we're creeping toward the mid- to high 20s? And given H&P's leadership in terms of the number of rigs that are still eligible for upgrade on pretty modest CapEx requirements, should we expect price momentum to slow at some point as H&P continues to take market share before we end up in the high 20s new build ZIP code?

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [8]

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Well, Tommy, I -- we don't think that we're going to see pricing that's going to reach the new build economics area. I mean, I think the fact of the matter is you're -- I think, if you're really going to get a reasonable rate of return on the types of investments on these new -- what a new rig would cost today, $24 million, $25 million, you really need close to $30,000 a day, so we're still several thousand dollars a day from that pricing point. And so I don't think that, that's where we're going to go. I do think that there is continued opportunity to push pricing. If you think about it in a mid-20s, we're -- we still have some capacity to push it to the upper limit to that mid-20s. And so I think we're going to continue to push towards that leading edge. So we'll start to see the average rate pushing more toward the leading-edge rate as opposed to it being on the lower end of that mid-20s.

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Thomas Allen Moll, Stephens Inc., Research Division - Research Analyst [9]

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Okay. That's helpful. And one follow-up. I wanted to dive down on the CapEx guide you gave for $650 million to $680 million, with roughly 40% of that allocated to upgrades. If I assume 12 a quarter, the math comes out to about $5.5 million per, which seems reasonable. My first question is whether that's the correct logic underlying the budget? And if you could confirm the willingness to flex that number, given final upgrade decisions are ultimately going to require contracts with customers upfront. And then second, I just wanted to ask for some more detail on the third portion of the budget allocated for reactivations and other bulk purchases. Mark, you gave us some helpful details on that in the transcript. I wonder if you could enlighten us a little more on those themes. In particular, on the reactivation piece, does that relate to the roughly 12 per quarter upgrades that you're thinking about? Or is there something else that, that would relate to?

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [10]

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Tommy, thanks. Starting with your second question first, yes, the reactivation relates directly to the upgrade cadence. And the other bit of that, the "bulk" purchases, relate to what has been a very quickly expanding rig fleet count for us over the last couple of years, coupled with a rig fleet that is drilling a lot more flex well for our client and is running a lot harder. We -- as I've said, just in a couple of years' time, we've gone from an average of 2 pumps per rig to nearly 3. So you can imagine the amount of capital spares one has to have on hand to be able to deal with any downtime or regular planned maintenance related to the various pieces of equipment. So there's a lot of stuff in there and other -- obviously, as I called out in my prepared remarks, tubulars fit that build as well. I hope that answers your question. If not, come back with a follow-up. The first part of your question, I think your math is correct. We're not going to -- we have been averaging about 12 rigs per quarter, but as you know, that varies quarter-to-quarter. And that's really dependent purely on customer demand that we're meeting. We are able to really flex our capabilities up and down related to the client's need in our family of solutions, and we can come up with a skidding or walking package as appropriate. As we look over the planning horizon, our intention is to build more walking -- to build out more walking rig capabilities so we have a more balanced fleet as we conclude the upgrade program. But as we move through the program, that will be dependent on direct customer discussions, because as we have said before, each and every upgrade that comes out is backed by a client contract.

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Operator [11]

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We'll go next to the line of Kurt Hallead from RBC.

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Kurt Kevin Hallead, RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst [12]

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So john, very, very interesting commentary here on the commercial and pricing models, and I appreciate the added information you've kind of provided. So if I recall my early days in this business that land drillers at some point were on a turnkey kind of basis and a footage drilled kind of basis. And that -- I envy that I had kind of mixed results from a financial performance standpoint at the time. Just wondering if you can kind of give us some context on that and how you guys feel more -- maybe what makes you more confident about the opportunity maybe to switch commercial models and generate better financial returns, vis-à-vis, just the straight dayrate model.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [13]

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Yes, Kurt. Yes, I have some -- when I started with the company in '87 and in the '90s, we did a lot of footage and turnkey work. And so that's not what we're talking about. We're not talking about going back to a traditional footage, taking on more risk model or turnkey, although there could be some modified versions of that. Obviously, the types of wells we're drilling today and the efficiency that we're seeing are much different than what we've ever seen in this industry before. And so that's really what we're addressing. Unfortunately, I don't have an exact answer for you. But what I do know kind of relates to what I said on the earlier question as it relates to partnerships. And as you partner with your customers and you come to realization that there's ways that both sides can win, because it's really not designed to be sides, both parties can win. And that's what we're wanting to do. I mean we're very pleased today that, as we've said, we're seeing much improved pricing, we have better margins. And -- but as you fast forward to where we're going to be 2 or 3 years from now, if we don't change some modeling now, we're not going to be in a stronger position as we would like and as our shareholders would expect us to be. So I know it's not a direct answer to your question. I don't necessarily see us going in a wide-scale turnkey-type operation, if that's what you're asking.

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Kurt Kevin Hallead, RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst [14]

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Okay. No, that's great. That's good. Appreciate that. And then follow-up would be, maybe midyear, going into third quarter, there's some discussion on varying land drilling conference calls that going into 2019, expectation was E&P companies would effectively be resetting their budgets at the higher oil price levels than what they were set for 2018. And obviously, you could set the stage for a very strong and robust demand for land drilling rigs. And now we've kind of round tripped on oil prices as you've indicated and we've all seen in the screens. If the E&P companies keep the budgets set in the $50 to $60 range, how would you handicap the growth in overall drilling activity on a full year basis in '19? I know you've already give us good guidance on the initial start of your fiscal year. But kind of wondering how you would handicap it if we're still in a $50 to $60 budgeting environment.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [15]

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Yes. I -- it's interesting because obviously, we've had a lot of conversations with various customers, and the feeling that I've gotten through that is whether it's $55 to $60 or whether it's up to $70, I think the budgets are going to remain pretty strong. The question, of course, is how much actual rig count growth do we see. And I think a portion of that is a function of an earlier question and some of the commentary that we have related to the replacement cycle and the number of legacy, much older rigs that are still out there working. And so if the average lateral that today we think is around 8,000 feet, which is up from around 6,000 feet in 2015, 2016, if that average lateral continues to trend higher, which we suspect that it will, it goes to 8,500, goes 9,000 foot, then you begin to put a lot of these older rigs, less capable rigs in a position where they just can't perform at the same levels as a super-specced rig does. So I think our belief is that we're going to continue to see demand for super-spec. How that relates to the overall rig count growth is very hard to determine. But we sure don't see any customers that are readjusting budgets or readjusting rig count. We haven't seen any of that.

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Operator [16]

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And we'll take our next question from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [17]

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I just wanted a just kind of a quick one. Can you just advise us of how many upgradable rigs you still have? I believe back in the September presentation, you listed 76 rigs and 32% of those contracted at that time.

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [18]

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We have about 65 approximately rigs that are available for upgrade. And in our view, that is about 50% of the industry's upgradable inventory.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [19]

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And how many of those are active?

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Unidentified Company Representative, [20]

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25.

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [21]

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Yes. So 25 of the 65 are active.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [22]

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Okay, great. I appreciate that. Then I'd just like ask a little bit broader question. On this call, you've already provided some really thoughtful color concerning pricing and changes in the industry. I want to bring the apps and these value-added services under the discussion. Do you -- you have this evolving model of the rig as a digital network with less human error. And do you see that as something that can further enhance revenue generation on the rig? Or is it more about increasing utilization as you continue to build out an upgraded fleet?

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [23]

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Yes. Jeff, that's a great question. And our intent is that those FlexApps, automation technology like AutoSlide, those are additional value streams that we would get an additional compensation. And again, it's back to how's the best way to structure that. I'm sure with every customer it'll be a little different. But the fact is we're investing real effort, real money and time into these -- into the development of these apps, into the development, into our software, into our FlexRig operating system. And so as Mark said, I think our R&D budget, the $25 million and $30 million, we're going to continue to have investments. Our hope is that we continue to make acquisitions of technology-type companies. And again, those -- the focus for those technology are not just for the sake of the technology but rather for the value add that, that technology can provide. And so what we're trying to understand is how do we best provide another level of value for our customers. MOTIVE is a great example. We've seen for a long time at H&P and other operators and billing contractors have as well that the human directional driller on the rig, if he's -- if he isn't the most effective, he can destroy value proposition for the FlexRig. And so having a bit guidance system that enhances that directional driller's capability is a big win, plus it delivers a higher level of wellbore quality, less torque velocity, which have even added benefit to overall performance of downhole drilling tools, ultimately to the overall quality of the wellbore. So all of those, our intent is to see the compensation that's related to the value proposition that we're providing. And some of that, like AutoSlide, is still to be determined. We have really early success that we've seen with the 2 customers that we're in beta testing with. It's going really well. So more to come on that, but our intent is to get an additional revenue stream.

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Operator [24]

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We'll go next to Brad Handler from Jefferies.

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Bradley Philip Handler, Jefferies LLC, Research Division - MD & Senior Equity Research Analyst [25]

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Let's talk about CapEx some more, please? It was higher than I was expecting, your budget for next year. And maybe you could accuse me of just not listening carefully enough. I think I could stand guilty of that. But let's talk about that a little bit. And maybe the prospective I'd love you to take is -- although I'm hardly going to ask you to start talking about fiscal 2020, I'm curious to -- just to understand what may come -- what may roll off versus what may stay or what may grow in terms of capital requirements. So for example, if you're building up your inventory of spares, presumably, that's not -- there's a little bit of onetime-ishness within that, right? You sort of have to get it to a better place than it is. At the same time, if lateral lengths keep growing and the demands on your rigs keep growing, then your maintenance CapEx might continue to rise. And I'm not exactly clear about the reactivation concept. I guess, I probably have made the mistake of thinking that the $3 million to $8 million sort of incorporated reactivation expenses, and obviously, it does not, so presumably that stays. But does that get worse as you dig deeper and deeper into your inventories, right, as you continue to roll rigs out, say, in 2020? So I know there's a lot of moving pieces to that, but hopefully, you can -- I can remind you of them and you can speak to that. But that would all be very helpful to hear.

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [26]

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Brad, please provide the prompts as we move along so that we make sure to (inaudible). But as we said, we have 238 rigs working today and we have another 40 from one of the previous questions and the upgrade inventory that are currently idle. So as we work through the upgrade inventory, one can get to a high 200 number of rigs that would work to your question in fiscal 2020. All things being equal at that point, assuming we have not moved to new build pricing territory, we certainly would see a reduction in the capital expenditure levels and therefore, an increase in free cash flow. So if you -- and it could envision what we still believe is an accurate $750,000 to $1 million per active rig for maintenance CapEx per annum. You would have some other amount of fleet-wide spares, for example, you could layer on top of that. But that number, I could imagine it being somewhere from, I don't know, $275 million to $350 million per year at a high 200 rig count flat state.

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Bradley Philip Handler, Jefferies LLC, Research Division - MD & Senior Equity Research Analyst [27]

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Okay. Okay. I get that. The -- on -- if we start to think about -- one of it -- one of the elements in my too long question whether reactivations do get more expensive as you're digging deeper into inventory.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [28]

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Is that (inaudible)?

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [29]

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I think we've sort of crescendoed towards this $4 million number I mentioned in the prepared comments. I don't really see it getting higher than that as we move through these remaining 40.

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Bradley Philip Handler, Jefferies LLC, Research Division - MD & Senior Equity Research Analyst [30]

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Okay. But then the -- I see your point. Then Flex 4s are just a different -- are a different animal altogether if you move towards that set, right? Not necessarily in worse shape. It's just a different category rig. Is that fair for me to think?

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [31]

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Yes, that's fair. And as John said in his prepared comments, we see market opportunity for those separate and apart from the super-spec arena.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [32]

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Yes, Brad, and I think we talked about this, it may have been a question on the last quarter or we talked about it previously, and that is the FlexRig4s, we -- because of all the effort we have in the upgrade program on super-spec, what we haven't really spent a lot of time on is looking at the Flex 4s and what else can we do with those to be even more competitive in the market than what we are right now. But to your point, those rigs are in no worse shape than the Flex 3s that we're bringing out. As Mark said, a lot of these rigs have been stacked on average for 4 years, so we've maintained them very, very well. But a lot of that equipment that is equipment that needed to be used has been used on other rigs. There's no reason for that equipment to sit there and deteriorate. You want to use it.

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Bradley Philip Handler, Jefferies LLC, Research Division - MD & Senior Equity Research Analyst [33]

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Sure. Okay. All right. That good. That gives me a lot to think about. Maybe a shorter question for me on daily operating expense. You've -- you guys have been very consistent with laying out sort of the run rate in the high 13s versus where you're out. But as we think about OpEx through the course of fiscal '19, should that number be trending lower per day because -- essentially because the average rig count continues to rise? Or does it hold because the reactivation pace continues to layer on top of it and self-insurance actually reserve what they are?

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [34]

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Brad, as we move through fiscal '19, I think we'll certainly have the upgrade and reactivation program keep us at the higher end of the range. But to the same point, as we move past that and into 2020, you'll have an absence of reactivation cost, again, assuming that flatline rig count, which is a very clouded crystal ball looking out pretty far in time. And simultaneously, you have less inactive rigs. So yes, I think you start moving from the 14 to 7 range closing to the 13 to 7 over a much longer planning horizon.

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Operator [35]

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And we'll take our final question from Scott Gruber from Citigroup.

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Scott Andrew Gruber, Citigroup Inc, Research Division - Director and Senior Analyst [36]

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So a couple final ones for me. Just a housekeeping one. Mark, the step-up in the ETR for the year, would the increment largely be cash taxes?

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Mark W. Smith, Helmerich & Payne, Inc. - VP, CFO & CAO [37]

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Yes. State and foreign jurisdiction cash taxes.

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Scott Andrew Gruber, Citigroup Inc, Research Division - Director and Senior Analyst [38]

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Okay. Got it. And then just coming back to the traction you all seem to be getting on these alternative models, John, it sounds like you'd prefer a model that incorporates more bonus features versus moving back towards the pure footage or turnkey models that we've seen the past. Is that the right way we should think about it?

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [39]

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Yes. I think it's -- use the performance model as an example. The idea is for everyone to win. We want to continue to enhance our customers' efficiency, including wellbore quality, including wellbore placement and doing that in a more autonomous, reliable fashion. I mean FlexRigs are already more -- the most reliable fleet in -- rig in the fleet as you look at the performance over time. But as you add on these technology adders, there's even more reliability, higher levels of reliability. So the idea is not to, like I said earlier, not to go into necessarily a turnkey model, but it's some sort of a performance model, a footage-type arrangement. We've even done some lump sum-type things. But we just have to have a -- have it on a larger scale, so we're protecting ourselves longer term as these well frackers get faster and faster.

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Scott Andrew Gruber, Citigroup Inc, Research Division - Director and Senior Analyst [40]

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Got it. Do you think it'll be easier to get paid in full and realize the full value to the new technologies through these alternative models and through bonus features versus just getting paid incremental rate?

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [41]

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Well, I -- if you think about the technologies that we're providing, use AutoSlide as an example, and again, it's not fully commercial yet, but assuming that we can get there, we believe that's a technology that no one else really has. And so if that's something that the customers want that they see value in, then there's a value proposition there for them to receive and be willing to pay for. And so I think it's a distinctive -- it's distinctive, and it's differentiating. And it's very much like what I described or at least tried to describe was where we were when we rolled out the FlexRigs to begin with. Part of the thing that was missed early on is that AC drive technology was a differentiator. And it wasn't just another rig, it actually had components that would drive higher levels of value, and we got paid for that. And again, as well frackers get faster and faster, it's harder and harder to get paid for that. And so as we layer on additional technologies and capabilities, we've got to figure out ways to get paid for. That's really the kind of simplicity of it. I'm really not in a position to share a whole lot about how we're going to do it. I think each customer has the potential to be slightly different, and that's fine, it's just as long as we're getting recognized and compensated for that.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [42]

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Okay. Erika, that was the last question?

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Operator [43]

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Yes. I'd like to turn it back over to John Lindsay for closing remarks.

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John W. Lindsay, Helmerich & Payne, Inc. - President, CEO & Director [44]

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Okay, Erika. Thank you. So everyone, thank you again for joining us this morning. As always, we're very appreciative to all of our folks at H&P for their efforts on focusing and driving value for our customers. We are optimistic about the future and optimistic that we can compete and perform during 2019. So we're looking forward to it. Thank you, all, and have a great day.

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Operator [45]

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I'd like to thank everybody for their participation on today's conference. Please feel free to disconnect your line, and have a wonderful day.