Helmerich and Payne Inc (HP) 2017 Q1 法說會逐字稿

Good day everyone, and welcome to today's first-quarter earnings call.

(Operator Instructions)

Please note, this call may be recorded. I will be standing by should you need an assistance. It is now my pleasure to turn the conference over to Mr. David Hardy, Manager of Investor Relations. Please go ahead, sir. Thank you, Savannah, and welcome, everyone to Helmerich & Payne's conference call and webcast corresponding to first-quarter of FY17. With us today are John Lindsay, President and CEO, and Juan Pablo Tardio, Vice President and CFO. John and Juan Pablo will be sharing some comments with us, after which we will open the call for questions.

As usual, and as defined by the US Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions, are subject to risks and uncertainties, as discussed in the Company's annual report on Form 10-K and quarterly reports on Form 10-Q. The Company's actual results may differ materially from those indicated or implied by such forward-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 on the last page of today's press release. I will now turn the call over to John Lindsay.

Thank you, Dave. Good morning everyone, thank you again for joining us on the call.

We are pleased with the improving outlook in the US land market. The downturn has been a challenging two-year journey, and H&P has been preparing for the opportunity this upturn presents. The Company has seen significant increases in rig activity levels and market share over the last few months. I believe our people have responded in a remarkable fashion, both in terms of the number of rigs activated, and the value provided to customers and ultimately to shareholders.

There are three main areas I'd like to turn your attention to this morning: First, is the success we've had in reactivating FlexRigs. Our customers have added FlexRigs in all of the US basins in which we work.

Second, I will provide an update to our FlexRig super-spec upgrade program, and our progress in providing the right rig for our customers' drilling program. Finally, I will discuss a timely CapEx increase which aligns with our outlook for the next two quarters and supports our ability to continue to build market share.

First, let's discuss our success in reactivating FlexRigs. Since the last earnings conference call on November 17, 2016, we have put 36 FlexRigs to work, which is the equivalent to delivering a FlexRig to active status every 47 hours. Of those rigs, 21 are in the spot market, and 15 on term contract. Although spot pricing remains low, we are seeing some pricing improvements for high-quality, high-performing AC drive rigs.

The Permian led the way with 12 rigs, six each in the Eagle Ford and SCOOP and STACK play. We had three in the Haynesville, two each in the Marcellus, Utica, and Piceance basins, and one apiece in the Niobrara, Woodbine, and Texas Gulf Coast.

From a FlexRig model perspective, 23 out of the 36 were FlexRig3s, two were FlexRig4s and 11 were FlexRig5s. As we commented on the last call, we continue to have a great demand for the FlexRig3. It is the workhorse of the fleet, and delivers great value for the customer on single well and pad locations.

Of these 36 rigs, approximately two-thirds were classified as super-spec. We have also added 11 new customers since the last call, and momentum has been building as a result of the performance our folks are delivering.

Even with the high delivery cadence, we have maintained problem-free startups. This means safe, efficient and reliable performance right out of the gate. And this is being rewarded as evidenced by the continued demand we are seeing from customers today for rig deliveries, at least through the remainder of our second fiscal quarter of 2017.

Our two most active basins today are the Permian and the SCOOP and STACK play. The Permian remains our most active operation, and we have 60 rigs contracted, coming off of a low of 38 contracted rigs, and at one point last summer, we only had about 23 operating rigs. We have 62 idle FlexRigs in the area, 42 of which are 1500 horsepower and we expect to continue to have opportunities to grow our active fleet in the Permian.

In the SCOOP and STACK today, we have 27 rigs contracted, coming off a low of 15 contracted rigs. We estimate that H&P has about 56% of the available 1500 horsepower AC rigs in US land today, providing more capacity than any of our competitors in the market. We currently have 139, 1500 horsepower AC FlexRigs under contract, and 187 idle and available to go to work in the US.

We have 20% market share of the US land horizontal and directional drilling market, with our closest competitor at 12%. We believe that our overall market share in US land has expanded to approximately 18% from 16% over the past few months and we been able to grow our market share from 15%, since the peak of activity in 2014.

Since the trough of the downturn in May of last year, we have more than doubled our number of active rigs to a current level of close to 140 rigs. Putting that many rigs back to work successfully is a complex effort, and involves many constituents. A significant element in our success is our workforce staffing effort. That team has been responsible for hiring previous employees for our reactivated rigs. We've rehired over 1,500 former field employees since May of last year, and it shows in the morale of our people across the board.

Another group that has contributed significantly is our customer account managers and contract management teams. With the volume of rig activations, they have all contributed to growing our business, and expanding our customer base and market share. Those efforts have enabled adding 24 first time FlexRig users since the bottom of the cycle in May of last year. I want to thank everyone at the Company for working together as a team to achieve these milestones.

The second area I wanted to focus on is our ongoing effort to provide the right rig in our family of solutions for our customers. Our FlexRig design allows H&P to invest in our existing fleet, to enhance rig capabilities that will benefit our customers in the areas that require well designs which are more challenging and complex. H&P leads the industry with our fleet of AC drive super-spec rigs, that have 7,500 PSI circulating systems, multi-well pad capability, 1,500 horsepower draw works rating, and 750,000 pound hook load.

On our last call, we mentioned having approximately 80 of these rigs, and as of today, we have approximately 100 super-spec rigs in the fleet. The industry's capacity to provide additional super-spec rigs in a timely and cost-effective way appears to be limited today, with the existing industry rig fleet, which positions H&P very well for future expansion in this space.

Should there be a significant market demand for super-spec rigs going forward, H&P has the capability of providing approximately 270 super-spec FlexRigs to the market, without requiring any new builds. Solely through upgrades, where needed, to our current FlexRig3 and FlexRig5 fleet. Our uniform base of existing FlexRigs leveraged by our experience in design and construction, enables us to invest in our fleet for the future in a scalable and cost-effective way.

Finally, the last area I want to address before turning the call to Juan Pablo is an increase in our CapEx, which is driven by the improving market conditions and customer demand. Juan Pablo will go into more details in his remarks, but I want to underscore a few important points. A portion of this increase will be dedicated to super-spec upgrades to our FlexRig fleet, which will enable us to continue to be able to respond quickly to customers in this tightening market.

There are couple of important factors driving this. First, as a result of the high demand for FlexRigs, we have contract commitments for a large portion of our super-spec capability, and we want to make certain future deliveries aren't constrained. The upgrades include some of our standard super-spec features, the 7,500 PSI circulating systems, third mud pump, control, and data system enhancements, setback capacity, and Flex 3 pad capability.

We continue to have incremental demand from customers for additional Flex 3 skid systems. So we plan to increase our capacity to meet the significant demand from customers. Second, we will be adding our first prototype walking system to an existing FlexRig3. When this Flex 3 with a walking system is complete, it will also have all of the standard super-spec upgrades, similar to our super-spec capacity Flex 3s and Flex 5s that we have in the market today.

We expect the first rig to be delivered in the current quarter, and if there's demand from customers, we would plan to deliver a few more Flex 3s with walking systems in 2017. These CapEx increases and upgrades to our fleet are examples of having great flexibility to invest in our uniform fleet of FlexRigs, providing the right rig to meet customer needs, and adding value to shareholders. And now, I will turn the call to Juan Pablo.

Thank you, John. As reported this morning, the Company had a net loss of approximately $35 million during the first quarter of FY17. Nevertheless, as John described, the ongoing US land drilling market recovery has been providing exciting opportunities for the Company to redeploy a large number of FlexRigs into the market.

Following are some details on each of the three drilling segments. Our US land drilling segment reported an operating loss of approximately $31 million during the first fiscal quarter. However, the number of revenue days increased by approximately 23%, compared to prior quarter, resulting in an average of a close to 106 rigs generating revenue days during the first fiscal quarter. On average, approximately 73 of these rigs were under term contracts, and approximately 33 rigs worked in the spot market.

Excluding the impact of early termination revenues, the average rig revenue per day declined by approximately 2% to $23,891 in the first fiscal quarter, as the proportion of rigs working in the spot market increased significantly quarter to quarter. Excluding lawsuit settlement charges and adjustments to self-insurance reserves, the average rig expense per day increased by about 13% to $15,064.

A significant sequential increase in this average was expected as a result of a much lower proportion of rigs generating revenue days while on standby. The increase in the average, however, was further amplified by a larger than expected number of rigs that returned to work during the last few months, generating additional upfront startup expenses that were absorbed during the first fiscal quarter.

To provide some context, the number of rigs generating revenue days increased from 102 to 138 since our last conference call in mid-November. As a result of these changes in daily revenue and expenses, the corresponding average rig margin per day during the first fiscal quarter was $8,827. This segment generated approximately $9 million in revenues corresponding to early termination of long-term contracts during the first fiscal quarter.

No early termination notices in the US land segment have been received or announced since last July, but given prior notifications, we expect to generate approximately $6 million during the second fiscal quarter, and a total of over $25 million during several quarters thereafter, in early termination revenues. Since the peak in late 2014, we have received early termination notifications for a total of 88 rigs under long-term contracts in this segment. Total early termination revenues related to these 88 contracts are estimated at over $460 million.

As of today, our 350 available rigs in the US land segment include approximately 140 rigs generating revenue, and 210 idle rigs. Included in the 140 rigs generating revenue are 89 rigs under term contracts, 87 of which are generating revenue days. In addition, 51 rigs are currently active in the spot market, for a total of 138 rigs generating revenue days in this segment.

Three of the 138 rigs remain idle and on standby type day rates. Separately, the two rigs that are not generating revenue days include new build rigs that are waiting for the customer to be ready for delivery.

Looking ahead to the second quarter of FY17, we expect a sequential increase in activity in the range of 30% to 35% in terms of revenue days. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to decline to approximately $22,400, primarily as a result of a higher proportion of rigs working in the spot market.

Although spot pricing remains low, we expect to see average spot pricing for FlexRigs improve over the next few months, as we are now seeing leading edge day rates moving from the mid teens to the high teens. The average rig expense per day level is expected to decrease to roughly $14,900. Although we expect this average expense level to eventually come down to more normalized levels, the upfront rig startup expenses during this steep phase of the upturn, along with the carrying costs of still over 200 idle and available AC drive FlexRigs are temporarily and unfavorably impacting the average.

If we isolate rigs that remained active during the first fiscal quarter, their average expense level was still close to $13,000 per rig per day, which is similar to overall levels experienced in more stable prime periods like 2013 and 2014. This segment currently has term contract commitments in place for an average of approximately 86 rigs during the second fiscal quarter, 75 rigs during the remaining two quarters of FY17, 44 rigs during FY18, and 17 rigs during FY19.

These commitments include about 20 rigs that have been placed under term contracts since last May, with a pricing at slightly higher than spot market levels. Including these newly contracted rig, the average daily rig margin for rigs that are under term contracts has been declining from $15,000 to $16,000 range to an expected range between $13,000 and $14,000 per day during the second fiscal quarter.

Let me now transition to our offshore operations. Segment operating income increased to approximately $7 million. Total revenue dates remained flat, and the average rig margin per day increased by about 16% during the first fiscal quarter to $10,478 per day, excluding self-insurance reserve adjustments during the prior quarter.

As we look at the second quarter of FY17, we expect quarterly revenue days to decline by approximately 10%, as one of the seven offshore platform rigs that were generating revenue days during the prior quarter, is expected to be released by the operator during the second fiscal quarter. The average rig margin per day is expected to increase to approximately $12,000 per day during the second fiscal quarter, as five of the six rigs that are expected to continue to generate revenue days at the end of the quarter will soon be working under operating day rates, while the remaining one rig is expected to continue under a standby type day rate.

Management contracts on platform rigs contributed approximately $4 million to our offshore segment operating income during the quarter. And are expected to generate around $3 million in operating income during each of the next few quarters. Moving on to our international land operation, the segment reported operating income of approximately $1 million during the first fiscal quarter.

Excluding the impact from early contract revenue of approximately $5 million, the average rig margin per day decreased sequentially by approximately 16% to $8,883 per day. Revenue days also declined by approximately 16%, primarily as a result of an early termination notice related to five of our rigs under long-term contracts in the segment. We expect early termination fees related to the notification to favorably impact our operating income in the near future.

As a result of the recent early termination notice, we expect international land quarterly revenue days to decrease by approximately 38% during the second fiscal quarter. As of today, our international land segment has 8 of the 38 rigs in this segment generating revenue days, including five in Argentina, two in Colombia, and one in Bahrain. Seven of these rigs are under long-term contract and two of the seven are scheduled to roll off their term contracts during this fiscal year.

Excluding the impact of early termination revenues, the average rig margin per day is expected to decrease to approximately $5,000 per day, primarily as a result of the higher overhead expense per revenue day, given the very low utilization rate in this segment. We will continue to manage overhead expenses, while at the same time remain mindful of the potential recovery in international markets, which may simply be lagging the recovery that we are now experiencing in the US land market. When we combine all three of our drilling segments, and exclude rigs with early terminations, we currently have an average of approximately 86 rigs under term contracts expected to be active in FY17, 51 in FY18, and 22 in FY19.

Let me now comment on corporate level details. As a result of improved market conditions in the US land market, our FY17 CapEx is now estimated to be around $350 million, about 30% of which is expected to be related to maintenance CapEx and tubulars, and the remainder mostly to upgrades of our existing fleet.

Given the strength of our balance sheet, we continue to be in great position to sustain regular dividend levels, along with ample flexibility to take advantage of opportunities going forward. The effective income tax rate on the loss for the first fiscal quarter was approximately 35%. The effective income tax rate for FY17 is at this point expected to be around 33%, which is a reduction from our prior estimate of 36%, due primarily to considerations related to foreign jurisdictions, where tax benefits for operating losses are uncertain. With that, let me turn the call back over to John.

Thank you, Juan Pablo. Before we open the call for questions I want to reiterate a few points. There is optimism in the market post-OPEC meeting. With stronger oil prices and an improving outlook, we will continue to a reactivate idle rigs out of our facilities safely, efficiently and cost-effectively.

It is gratifying to see that many of the strategies we employ to prepare for this eventual increases are bearing fruit as we redeploy rigs to the field. Our fleet is particularly well-suited for the more technically challenging wells being drilled today. I think more important, we have the people, the systems, and the operational support structures in place to drive the highest levels of performance and reliability for our customers. And Savannah, we will now open the call for questions.

(Operator Instructions)

We will take our first question from Angie Sedita from UBS.

So, John, could you give us a little bit more color on your pricing commentary and maybe some thoughts about the pace of pricing as we go into 2017, and where we could potentially end the year? And then, second, on the pricing side, do you expect it to remain very narrowly focused on the super-spec rigs, or could it start to spread to other rig types?

Angie, what oil price are we going to have?

Let's assume it is where it is today. It's flat.

Okay. I think there's no doubt that we have some pricing power in the market, now. I mean obviously, everyone has been pleasantly surprised with how quickly things have moved. And so it has been hard to keep up with it, quite frankly.

But there is pricing power, as well as I do, it's pretty hard to see out past this quarter. We obviously have a lot of calls coming in, and customers wanting rigs. And for February, March, and even some April deliveries. And so with that, we would expect to see some continued pricing.

I think the question, if oil prices remain in this range, again, I think if you look at the very, very, low rig count environment we've had over the last year or previous to this uptick, has been a function of really low oil prices obviously, and customer spending within cash flow. So with these new levels, the question is, how many rigs does it take? I think right now it appears that we're on target as an industry to potentially get -- we're almost at 700 so you would think that 800 is within our sights.

And so I think again, in that case, it's going to be tight, and I think, to your question on super-spec, I do think that there's going to be pricing power on super-spec, as you heard. We've even put up couple of Flex 4s to work. I think clearly the majority of the focus is going to be on the higher end, higher spec rigs, based on the types of wells that we see customers drilling today.

Okay, that's helpful. I guess as a follow-up, quickly on the 800 rigs in our sights, is that for 2017? The 800 could be in our sites? And then second in your prepared remarks, you made comments on the industry's ability to upgrade the super-spec as being limited, and maybe you can give us a little more color there?

On the limited, I think if you look at the inventory of rigs that are capable of being upgraded to how we have defined super-spec, there's only what? David, is it still around 300?

That's correct.

Around 300 rigs, and the majority -- half of that is -- over half of that is H&P, and then the other is made up of two or three, maybe four contractors, for the most part. So it, it's a pretty small group of players that have access, at least what we think are the rigs that are going to be in the highest demand. So I think that's the part of the scarcity, if you will, even though obviously the rigs are there, and they can be upgraded.

The 800 is really just looking our rig count, and understanding where we think we're going, based on the commitments that we have had, and maintaining an 18% to 20% market share. That's how we get to the 800. And again, it's a function of what oil prices do and how the outlook is. But right now, it sure seems like there continues to be demand for those types of rigs.

All right, perfect. Thanks for the color, and I'll turn it over.

We will take our next question from John Daniel with Simmons & Company.

Two questions for me. On the international, can you speak to any of the visibility you might have for rig reactivations as you roll through the year?

John, we really don't have any positive outlook in that respect. I think you have heard several people say -- and we've known this for several months, that while we hit the bottom in US land last summer, it may this summer before we completely hit bottom in international. So we don't really have any insight. We have had a few bids, that we have participated in. But I don't know of anything that is coming out of that.

Okay. And appreciating the fact that you don't like to give guidance beyond current quarter, but with what you know in terms of relative stability at this point on activity, I'm assuming. And knowing you are burdened with some overhead costs, is the cash margin guidance for the current fiscal quarter, is that representative of a range at least as we go through the rest of this year, barring a pickup in activity?

John this is Juan Pablo. I think that is the best guess we would have at this point. But certainly many factors could influence that going forward, and we'll try to keep folks informed of any developments there, but at this point it's a good starting point.

Okay, and then last one for me is in the walking system that you're putting in. Can you just provide some color? I'm assuming an XY capability, and was that at the request of the customer> What prompted the initiative here to make the investment?

Well John it hasn't been at the request of the customer. And obviously, there's been a lot of focus on the walking systems, going back at least two years, maybe even three years. And we've commented several times that we have the capability to do it, if it's something that we see the potential for, for growth, and it's a prototype.

And we think it will be a good rig. It will be again, another nice option to be able to provide to customers, if the demand is there. And I think that's really the question, is what demand we are going to see out of it.

Obviously at this stage, like I said, it's a prototype, and we have -- we do have a job for the first rig. We're not building it on spec. But if we see some demand, we will build some additional. And again from our perspective, we talked about -- in our prepared remarks, that in addition to that, we're also having high demand for Flex 3 skid systems.

And I can tell you, three or six months ago, I would have never guessed that we would be getting to the end of our availability on our Flex 3 skid systems. So customers like the Flex 3 skid system, the walking application obviously by definition is bidirectional, or omnidirectional. And I think this will be a good addition to the fleet.

Thank you for your time.

We will take our next question with Robin Shoemaker with KeyBanc Capital Markets.

John, I wanted to ask you about term contracts. You mentioned you have signed a good number here, as your rigs have gone back to work. So how should we think about a term contract today, compared to where we were a couple of years ago, when you were assigning two or three year contracts? Obviously it's different. Could you speak to the duration, and in some way to the premium that you would expect over spot, for signing a term contract today?

Yes Robin, just in general, obviously these term contracts are much different than what we entered into previously. Obviously, back then we were building new rigs, and we were getting great returns and three-year term contracts. This is really more about the customer.

I think, in a few cases, we're getting, ensuring we're getting a pay back in some investments that we are making in the rigs. But more than anything, it's more focused on the customer, and in particular areas. I think the average term is little over a year. So it's not like we're locking into a long period of time.

There is a premium. It ranges a couple thousand dollars a day range, but that's about all that we'll really talk about. I doubt you had too many questions other than that. Again, it's a relatively small number if you look at it in context of what we've entered into, with the overall working fleet and the capacity of additional rigs coming on. Again, things have moved very quickly.

Okay, thanks. And then, as they have moved quickly, what is happening in terms -- I mean, could you describe your hiring initiatives? I know you had a policy or strategy of keeping your most experienced people during the downturn, and having them work at lower level positions. So as these rigs go back, is that all working according to plan, and you see any possibility for upward pressure on wages in this very active period of hiring that you're going through?

That's a great question, and it has worked out very much like we had planned In my prepared remarks, our folks have just done a great job. Our workforce staffing group has done excellent.

They are working overtime and bringing existing or previous employees back on, and also obviously beginning to hire some new employees. So there's a lot of interviewing going on. A lot of processes that are happening. We have been very, very pleased with it.

I think we've had a little over 80% of acceptance rate. And very little turnover in the previous employees that we have brought on. The ability to move people that have been bumped back in position from floor hand to driller or driller to rig manager, or rig manager to superintendent, as you can imagine, has a huge impact, positive impact on morale, everybody is excited about it. Including everybody here in Tulsa.

It's been fun to see, and it's good to see rigs going back to work. So that part of it has worked out very well. Obviously, there's a lot of demand for people. I'd like to think that H&P is in a great position. We've not had issues hiring in the past.

I don't expect we'll have issues hiring today. We haven't had any increases in wages, but that's always something that we keep our eye on. Just make certain that we are paying our folks competitively. We did not have a wage reduction during the downturn.

So obviously, our employees that are moving back up into their previous position after being bumped back are in fact getting a raise. They are getting an increase from what they've been doing compensated. So that's obviously adding to the optimism of our folks.

Okay. Thanks a lot.

Thank you. We will take our next question from Waqar Syed from Goldman Sachs.

John, when you expect your OpEx in the US land to get back into that low $13,000 range?

Well Waqar, that's a tough one. Again, I think, going back to Juan Pablo's remarks, the rigs that are working obviously are working at that level. It's the impact of having as many rigs coming on as what we've had. That's a tough one to call.

If you could tell me again how many more rigs we're going put out next quarter and the quarter after that, we could probably begin to give you an estimate of that. But I think everyone around this table is surprised at how quickly things moved, and putting 36 rigs back to work in less than 70 days is quite a number of rigs. I really can't answer the question, obviously we're focused on it. I think we're in a position to get it back down into that $13,000 range.

I think the thing to keep in mind though, too, Waqar, is that, and I've said this before, and I think it gets lost on people because they haven't really experienced it. These rigs are working harder. Not only are we drilling wells faster, we're moving rigs more often, pump pressures are higher, expendables on 7,500 PSI systems are more costly than 5,000 PSI obviously. And so for us to be able to keep our costs in range that we have over time is really pretty impressive.

So we have in fact, lowered cost from that perspective. But again, it's a tough one to call. Juan Pablo, do you have anything to add?

No.

So let's say if the base slows down to picking up 5 to 10 rigs per quarter rather than 30+, when we get back to that level, if that case, would we be able to resolve most of the incremental costs, so you get into that $13,500 range?

This is Juan Pablo. I think that's a fair assumption. What happens also is that the activity continues to go up. The denominator grows, and it's able to absorb much of that. So there's a few moving pieces to that, but I think your comment is fair.

Waqar, if you look back at 2009, 2010, it's very similar. The only difference then is we didn't have near as many idle rigs, we didn't have near as large a fleet. And on a percentage basis, we didn't nearly idle as many rigs.

So you have to take that into account. But clearly, we got our costs back in line pretty quickly back then, and I expect we'll do the same thing here.

Now secondly, in terms of tubulars and drill pipe, do have an inventory of 5.5-inch drill pipe? How much -- what are the customers questioning these days? Do you hear a lot from customers struggling with respect to using these bigger drill pipes? And then if the need -- if there's demand for that, would you be buying that, would you be renting it?

We've used 5.5-inch drill pipe for many, many years, primarily offshore and in some international locations. We do have 5.5-inch drill pipe in the fleet. We have purchased some 5.5 over the last year. It's not a large inventory.

There's not what I would consider a huge demand pool for 5.5 Most of it is 5 inch pipe. And there still some customers that have 4.5.

But I think for the most part, 5 inches is in demand. I think if 5.5 goes into demand, then again we'll have to, will have to begin to order that, and see what the supply chain looks like. I'm not really familiar with what the supply chain looks like, in that respect.

Would you have to make any changes to your top drives, if the trend moves towards that? Or do you think the top drives can handle that?

We've had, I don't know how many strings we have out running right now with 5.5, either 5.5 we own or with 5.5 that the customer has rented. And no, there's no upgrade. Typically the upgrade that needs to be accomplished has to do with the racking board on the mast. But that's very small, very low cost. But we have plenty of horsepower capability and torque capability with the top drives we have.

And then secondly on the international markets, these early terminations, could you tell us what were the rationale for the customer? Are they reducing activity or they want to take advantage of the spot market? Are there labor issues? Why do you think the customers canceled -- terminated their contracts early?

Waqar, I can't speak to all the details. My suspicion it has to do with just international in general continuing to contract, contract in activity. That's really I think what it's about. I don't know of any other details associated with the other things you mentioned.

Okay. And then one final question for the second half of FY17, you mentioned $25 million in early termination revenues for US land. Is that right?

Can you repeat your question, Waqar? I missed the first part.

Yes for the second half of FY17, did you mention that early termination revenues in US land could be $25 million? Or I didn't hear it correctly?

I think the assumption is in general correct. But it goes beyond 2017. We provided some reference for the second fiscal quarter and then after that, meaning the second half of FY17, and probably also continuing into 2018, we have a total of $25 million that would be distributed during the following quarters.

Okay during the next, you said how many quarters?

I can't provide the exact details, but several quarters is fair.

Okay.

Waqar, back on your question on international, our five rigs are not the only rigs -- I mean, it's an industry issue, it's not focused on individual rig types or performance or anything related to that. It's just a general -- just part of the downturn at lower commodity prices.

Okay. Thank you very much.

We will take our next question from Timna Tanners of Bank of America

I get a lot of questions when I talk to investors about your dividend policy, so I just wanted to clarify. You do look like CapEx obviously going up, perhaps some restocking needs. If in a given year you have cash generation that's lighter than your dividend payout, does that affect the way you look at the dividend, or are you looking more on a long-term basis of your normalized cash flows? Thanks.

Timna, we look at it on a long-term basis at this point, for the foreseeable future. The expectation is that we will sustain the dividend level. We see no reason to change that at this point. There are many moving variables that impact the Company's liquidity, but our balance sheet and liquidity remain very strong. And so that provides opportunities not only to continue to return cash to shareholders through the regular dividend, but also, to take advantage of any opportunities that may come our way.

Good, I wanted that clarification, so that's really helpful. The only other question I had was related to some of the feedback you get from your customers. In particular, I was wondering if you could comment on their sensitivity to price, and how that's changed, perhaps? Or how you see that? And then also, any observations you may have on some rig obsolescence that could help temper the oversupply that we still see in the market? Thanks.

Timna, were you saying price as in day rate? Is that what you're referencing?

Absolutely. So the concern being that as you start to press for some pricing power, what push back you expect to get? Are they prepared to pay up for? Just general comments about how they are viewing their requirements of paying up for services. That's been a mixed bag from what we hear.

Right. I think it's pretty straightforward that cost of the rig is a really small component of the total well cost. However, it has a substantial impact on total well costs, because of well cycle times. I don't get the impression there's going to be a massive amount of pushback.

The reality is we have many rigs that have continued to work on term contracts at mid-20s, high 20s rates. And they don't have any negative impact on total cost of a customer's well. In fact, we don't hear anything about that. So clearly no one wants to pay any more than they have to, but I think in a tightening environment, in an environment where contractors are needing to invest, and the performance is there, I think customers will be more than willing to pay.

Okay thank you.

Timna, I think you had another question related to rig obsolescence. Was your question related to the industry in general, or were you talking about H&P?

I was asking more about the industry in general, because that's a theme we also hear, is to the extent that oversupply that were daunted by perhaps, and the industry was less than people believe, because many of these rigs will never be used again. Just wondering what you're hearing on that topic lately?

I think that's a great point. Go back to the peak in 2014 and there were over 1,800 rigs running and about 900 or less, probably 850 at that time were AC drive rigs. So that means the rest of the fleet was made up of legacy rigs, mechanical and SCR. And you can see, today, I don't have it in front of me, but I think mechanical rigs are what, less than 20%?

16%.

16%, and SCR rigs are 18%. AC drive rigs continue to capture market share at the peak in 2014, AC rigs made up 41% of the share. Today, AC rigs make up 66% and growing. So yes I think there's definitely an obsolescence factor.

Those rigs are, design-wise, those rigs are 50 years old. A lot of those rigs were built in the 70s and 80s. And it's going to be really challenging for those rigs to keep up. Particularly, if you're looking to put a rig like that on these longer lateral wells and drill the wells at the times that we are drilling them today, with FlexRigs. They're just going to have a tough time competing.

Thank you again.

We'll take our next question from Matthew Johnston from Instinet.

I wanted to hone in on some of the moving pieces around OpEx, for the reactivated rigs in the US land business. Is that mostly labor? Is it all labor that you're incurring up front? Or there any equipment upgrades that are being expensed in the P&L? And slightly connected to that, if we could get an update on what CapEx per rig looks like for the reactivated rigs, that would be helpful.

Matthew, this is Juan Pablo, as relates to the OpEx, the start up expenses, most of that is related to supplies and maintenance. And so that is absorbed as an expenditure. Anything that may be a capital investment of course is captured in our CapEx.

There are labor components as well. But there they're not as significant as what I would refer to as M&S or maintenance and supply. On the CapEx level and per rig, dollars in terms of upgrades et cetera, that's a difficult one to answer because there are different types of upgrades that are being performed on each rig, in particular.

There's a wide range. And in some cases, there are several upgrades related to the rig, and in some other cases, there's just one piece that needs to be updated or refurbished. It's a wide range.

The other piece that's important to note, the upgrade CapEx is not only related to rigs that are currently not working, and that are being upgraded to go back to work. It also relates to many of the rigs that are active, and that are upgraded in many cases during a rig move, or at some point during the operation. So lots of variables to consider there. No clean answer to the question.

Okay, fair enough. And then just going back to the walking system prototype for the Flex 3, curious if you could provide some details on what the capital costs might look like for that endeavor?

Well Matthew, at this stage, with it being a prototype and it not being out, we're not going to comment. We don't know the exact number. We do know that it's going to be a higher total investment than an upgrade of a Flex 3 with the skid system.

But we will talk about that more in the future. But I think at this stage of the game, it's best not to, not to comment on it any further. Again, not only are we adding a walking system, but we're also doing all of the other upgrades to get the rig to a super-spec. So again, I don't have the total cost in front of me. But we'll talk about it in the future.

Got it. Thanks, appreciate it.

We will take our next question from Sean Meakim with JPMorgan.

Wanted to maybe summarize a little bit of what we heard, a couple of different comments during the call. The rig counts ran faster than a lot of people were expecting through the holidays and now start the year. You are clearly taking some market share. Your guidance for the quarter seems to imply pretty big deceleration in rig adds in February and March versus December and January. And so I'm just curious if your perception is that E&Ps have just pulled forward their rig additions, and that the pace is going to slow pretty dramatically as we get closer to the midyear? Or do you feel like you have a sufficient line of sight to say that you can continue a pretty healthy pace towards that 800 number that you mentioned earlier?

Sean, based on what we think will go to work with our fleet, that's how we get to the 800. That's assuming we maintain similar market share. Again, as I said earlier, it's very hard to see past the next couple of months. And so, clearly, it could be that, between a 700 and 800 rig count is the rig count that is needed, with the cash flow that's going to be generated at those prices, at current oil prices. So that's the part that's hard for us to see.

We are preparing ourselves for a continued improvement in rig activity. We think we're prepared to do that, but obviously not clear if that's where the direction of the industry continues to go, based on what we know. I think part of what we've seen is, if you look back to 2009, 2010, the industry put 700 rigs back to work in 12 months.

I think if you look at the last six months here, I think we're on a track for maybe 450 to 500 rigs. I think I got that right. So we're just, we're just making an educated guess at this stage, but I think it's hard to see past the current quarter. So that's the reason why our numbers are presented the way they are.

That's fair enough. Thank you. Just one last quick one. Coming out of the downturn, it seems like there's a significant shift in demand towards some of the premier drilling services. Rotary steerable has got a lot of attention, moving away from some of the more conventional equipment. Are you seeing that out on your rigs? And over time, could a trend like that influence the types of services that you want to be participating in, with respect to bundling into your joint offering?

I haven't heard specifically on our rigs that rotary steerables are increasing. We've had rotary steerables on our rigs running pretty consistently over the last several years. I have not heard that the trend is increasing, although I wouldn't be surprised to see that.

As you know, we have our own rotary steerable tool. It's been very challenging to get traction bundling that with our services, and offering it to customers. But I think in general, I wouldn't be surprised to see rotary steerable continuing to gain traction.

At the same time, directional drillers with conventional down hole tools continue to get better. And obviously there's a cost differential, and sometimes there is an uptime or downtime differential with the rotary steerable with the higher technology tool. So obviously, as the technology gets better, the uptime gets better, that I think you'll probably see additional traction. But again, I apologize. I haven't seen that, so I don't know -- I don't know the details.

That's very helpful feedback. Thanks, John.

Savannah, we probably have time for one last question.

We'll take our last question from Brad Handler with Jefferies.

Maybe a couple of observations on my part. I want to apologize a little in advance if it seems rhetorical. But I am really asking for your color, and thoughts about it.

The first is, when you were idling rigs, we had a conversation, we all had a conversation around putting money into them to prepare them to come out more easily, more quickly presumably, and less expensively. In light of that, it's difficult for us to know how much of that you're seeing, as you bring rigs back out, but are you comfortable that still helped? Are you spending a lot less money now despite OpEx numbers we see rising?

I think that's a great observation, and a good question. And I've asked a lot of folks around here, and we have, obviously there's data and there's things you can measure, and then there's also some of the intangibles. And listen, this is not our first rodeo, we have gone through this before. We know what it felt like in 2009 and 2010, with far fewer FlexRigs. It definitely has been an advantage for us.

No way we would have been able to respond in the same fashion that we've responded up to this point, in terms of just sheer numbers of rigs. We've also had maintenance CapEx savings. The savings really go on and on. I think it would be great to have a summary, which we'll be there one of these days, where we can look back on it and say this is the value add ultimately, that we had again.

There will be some things that will be intangible. It's hard to measure the satisfaction of a customer when a rig comes out of the stack yard and moves in two days and drills a record well first rattle out of the box. That just didn't happen back in 2009 and 2010.

So I feel good about it, that we've, we've made a wise choice. Again, it was back to pay me now or pay me more later. I think it's paying off for us. Anything, Juan Pablo, you want to add?

I think that covers it well. Thank you.

Great. I really do appreciate the feedback on that. I guess the second question is, from a market share perspective, it's been interesting to watch, because in the first few months of the recovery, you probably lost a little bit of share that you had gained through the course of time in the downturn, and then it seems like over the last two months, you've gotten a ton of it back.

And there was a period of time when you were, and I know you were speaking in the beginning of December, your Flex 3 utilization was quite low, even with skidding systems. It was down at 50% relative to Flex 5 and the like, and now Flex 3s are coming back.

And so I'm curious, is this just a natural function of given where rates are, customers are going to grab the most capable rig, even if they don't need it? And then you drift into the next layer which is the Flex 3 system? Is that how you might characterize that lag and then catch up period from a market share perspective?

If you recall Brad, early in the cycle, which we knew that back in November, that November, October, that the trough was May, and that things were improving. But if you recall, the first operators that begin to put rigs to work were not really the traditional H&P type customers. So we were a little slow to respond, and a lot of the wells, quite frankly, were not more challenging horizontal directional wells, a lot of it was vertical work. So I think that's part of it.

I think the other part, that we've tried to speak to, and it's hard to do it, and it comes back to that intangible that I mentioned earlier. If you're a drilling manager, or drilling superintendent working for an operator, and you are going to go out and contract a rig, the last thing you want to do is go contract one that's going to shop on the first location and take 10 days to rig up, and then have all kinds of downtime, not have the right people. Not have the type of performance that you want.

And so being able to do that time and time again for customers, obviously improves the relationship, and additional work with that customer, but it also attracts other customers. We have 24 new customers since the trough that we have picked up, and a lot of those are picking FlexRigs because they've seen the performance that we've had in the field. So I think that's really what it is. Whether it's a Flex 3 or whether it's a Flex 5, I think that's really what it speaks to.

And of course we also have just more Flex 3s available in the marketplace. And of course, a lot of people have said, over time they have said some things negatively about those rigs, I think. But again I think you see the performance in the field today, and those rigs are going to continue to go back to work. That's a great observation. I appreciate that.

No problem. If it's okay, maybe I'll squeeze in one more, and we can keep it short, but I appreciate if you indulge me. Just coming back to the contracting. Maybe a little color on contracting strategy.

I guess I understand you got a little bit of a premium, but I might have imagined you would be optimistic about getting much better day rates at some point, not too far in the distant future. So how far -- can you draw some of the parameters around when you would choose to contract for a year at this point? How much of the fleet you would be willing to do? What maybe drove some of the decisions to engage in those contracts at this point?

Well again, Brad, great question. Obviously, there's a lot of competitive challenges associated with us discussing our pricing strategy, or what we are going to do, from a spot market, from a term contract perspective. We have some plans in place. We been through many of these cycles, and again, this one moved very, very quickly and as we all know, there was so much negativity, it was hard to believe.

I think most people felt like just any minute you're going to see oil prices go back down and things start slowing down again. I think we're going to able to take advantage going forward, as far as better pricing. And that's about all I can say as far as additional details on it.

I understand. That's perfectly reasonable. I appreciate that answer.

Thank you Brad, thank you, everybody. We'll hand the call to John for a few closing comments.

If there's anyone there that's hanging in there with us I appreciate it. Thanks for being on the call with us. I just wanted to finish just by saying that the Company's gone through really extensive efforts to enhance our organizational and systems health. And while we aren't finished, I think we are making great strides, and we're going to continue to improve.

We are really pleased with our ability to respond to the increasing level of demand in the marketplace that we've seen. And we believe that we are uniquely positioned to continue to gain incremental market share. Our competitive advantages remain in our people, in our performance, technology, reliability, and as we've discussed, our uniform FlexRig fleet gives us many advantages. These advantages should allow us to continue to outpace our competitors, and regain pricing power during this recovery. Especially as customer well designs become increasingly more complex and require higher spec AC drive rigs.

So again thank you for your time today, and have a great day. We'll see you at the next call. Thank you.

This does conclude today's first-quarter earnings call. Thank you for your participation. You may disconnect at any time, and have a great day.