Helmerich & Payne, Inc.
Q2 2014 Earnings Call Transcript

Published: 24 Apr 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to today's program. [Operator Instructions] Today's conference will be recorded. And at this time, it is my pleasure to turn the program over to Mr. Juan Pablo Tardio. Please go ahead, sir.

[Juan Pablo Tardio:]

Thank you, Mike, and welcome, everyone to Helmerich & Payne's Conference Call and Webcast Corresponding to the Second Quarter of Fiscal 2014. The speakers today will be John Lindsay, President and CEO; and me, Juan Pablo Tardio, Vice President and CFO. As usual and as defined by the U.S. Private Securities and Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that 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 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.

[John W. Lindsay:]

Thank you, Juan Pablo, and good morning, everyone. We had another strong quarter while achieving record revenues and record rig activity. Our continued success is a result of our people and new technology solutions that drive lower well costs for our customers. I would like to thank each of our employees for their contribution to the effort. Our drilling and safety performance continue to lead the industry and provide growth opportunities for the company. Our U.S. land rig count today stands at 287 rigs, up over 40 rigs since our second quarter call this time last year. We are pleased to announce 9 additional new builds this morning, comprised of 6 FlexRig3s and 3 FlexRig5s. When combined with the 35 previously announced new builds, we now have a total of 44 new builds for the 2014 fiscal year, all with long-term contracts and attractive economic returns. Of the 44 new builds announced, we have already delivered 25 with 13 FlexRigs that began work during the second fiscal quarter. We delivered 2 rigs per month for the first half of the fiscal year. And during April, we increased our construction cadence to 3 FlexRigs per month. Our plan is to continue that cadence at least through the remainder of the fiscal year. The market continues to be resilient, and we are encouraged by customer discussions for additional new builds. Our engineering, manufacturing and supply chain capabilities will allow us to respond quickly if future new build demand supports transitioning to a 4-rig per month cadence. As we review the macro environment, oil and gas prices remain stronger than expected for 2014. This has resulted in allowing many of our customers to expand their drilling budgets. The U.S. land industry activity is up around 80 rigs in 2014 according to the Baker Hughes rig count and H&P has been able to grow along with the expansion and capture incremental market share gains. The increase in activity has primarily been associated with horizontal wells with longer laterals and pad drilling requirements that FlexRigs are designed to drill. As a result, we expect our activity and market share to continue to improve. As evidenced by our new build contracts, our customers are seeking to both high-grade and expand their rig fleets as they transition into the development phase of the unconventional resource plays. This demand has improved the current day rate trends for our U.S. land segment on both spot market and term contract pricing. Juan Pablo will give more color on pricing in his comments. Overall, we are pleased with the improving trend. An instrumental part of rig demand in the U.S. is the Permian Basin. With approximately 500 rigs working today, it is the most active and one of the most promising basins in the world, and it should be no surprise it is our fastest growing area. 3 years ago, our Permian operation had 25 active rigs, and we found ourselves out of office and yard space. In the past 12 months, we have added over 30 rigs and are now operating nearly 80 rigs. Fortunately, we had the foresight to buy additional land in Odessa in 2011. We built a large facility and moved in, in 2012. Our timing was good as many have been surprised by the faster-than-expected switch to horizontal drilling in the Permian and the demand for Tier 1 AC drive rigs. The total horizontal rig count in the Permian today is approximately 300 rigs, which is a 200-rig increase from 2011. However, only 45% of the 300 rigs are AC drive rigs. As compared to the other large unconventional basins, like the Eagle Ford and the Bakken, where approximately 65% of the horizontal wells are drilled utilizing AC drive rigs. Contrasting these 2 metrics would indicate a lot more growth potential for AC drive rigs in the Permian, and we believe FlexRigs will continue to gain market share over competitor rig offerings. Even though the Permian has captured close to 50% of our new builds announced this fiscal year, we have also contracted new builds in the SCOOP, the Eagle Ford, Utica, Bakken, Haynesville, Woodbine and the Niobrara. We believe this demonstrates a continued high-grading of the existing rig fleet in basins that have had AC drive rigs working for multiple years. In addition to our growth and market share gains in the U.S., we are also pleased with the recently announced contracts with YPF in the Vaca Muerta shale located in the Neuquen Province in Argentina. As a reminder, in March, we announced that YPF contracted 10 existing FlexRig3s that are being sourced and prepared for service from our U.S. land fleet. The rigs were contracted with 5-year term contracts, with the first rig scheduled to be delivered this summer. The last rig should deliver during the second fiscal quarter of 2015. It has been reported that Vaca Muerta is estimated to hold over 20 billion barrels of oil equivalent. And reportedly, it is the only unconventional resource outside of the U.S. which is actually producing oil, and many believe it has the greatest commercial potential of all unconventional shale plays outside of North America. We see this as a great opportunity to assist YPF and other operators in developing this unconventional shale play. Our offshore fleet is now fully utilized, with the ninth rig receiving a commitment to work. The rig will be undergoing upgrades and is expected to commence operations early in fiscal 2015. Juan Pablo will share more offshore segment details in his remarks. All 3 of our operating segments had encouraging prospects for improving activity and are setting up nicely for the remainder of the fiscal year. On another note, I want to remind everyone of a point we have made on previous conference calls. Approximately 40% of all active rigs in the U.S. today are AC drive rigs. That is over 700 AC rigs out of approximately 1,750 currently active rigs. The remaining 60% of active rigs are comprised of legacy SCR and mechanical rigs, Tier 2 and Tier 3 rigs. The past 5 years have demonstrated a consistent trend whereby AC drive rigs have replaced legacy rigs. The AC rig market share has grown from 15% to over 40%, even with premium pricing levels as compared to the legacy equipment. The industry has been forced into a restructuring of the fleet profile during this replacement cycle and are still having to manage aging SCR as well as mechanical rig fleets while drilling these complex horizontal wells we've been talking about. Fortunately for H&P, this hasn't been the case. Today, we are only working AC drive FlexRigs in U.S. land unconventional resource plays. We believe the fleet uniformity of the Flex 3, the Flex 4 and the Flex 5s are paying dividends with regards to maintenance costs, training effectiveness and providing a lean manufacturing environment. We will continue to strive for improved and more reliable levels of performance. Let me conclude my remarks by noting H&P's long-term strategy for growing shareholder value. We will continue to drive innovation at the rig site and in the back office. We will invest in technology to drive safety improvements for our people and operational excellence for lowering our customers' drilling costs. And finally, we will continue to invest capital that results in attractive returns. Going forward, we believe H&P is the best-position land drilling contractor to capture this ongoing market share opportunity, both in the U.S. and international markets. And now I'll turn the call back to Juan Pablo.

[Juan Pablo Tardio:]

Thank you, John. The company reported $893 million in revenue during the second fiscal quarter 2014, along with $255 million in operating income and $175 million in net income. In trying to outline some of the key drivers that led to these results, I will first review each of our drilling segments and will then expand on other noteworthy considerations. Our U.S. land segment led the way, delivering $245 million in segment operating income. The number of revenue days increased by about 3.6% from the prior quarter, resulting in an average of approximately 270 active rigs during the second fiscal quarter. In average, approximately 155 of these rigs were active under term contracts, and approximately 115 rigs were active in the spot market. Excluding the impact of having only 90 calendar days in the second fiscal quarter as compared to 92 in the prior quarter, the average number of active rigs increased by almost 6% as compared to an average of 255 active rigs during the prior quarter. Excluding early termination fees, the average rig revenue per day was practically flat at $28,037. And the average rig expense per day was up by approximately 1% to $13,080, resulting in an average rig margin per day of $14,957. As of today, the 325 available rigs in the U.S. land segment include 287 contracted rigs, 33 idle rigs and 5 rigs currently held for the YPF Argentina project. Of the 33 idle rigs, only 1 was an AC drive FlexRig. The 287 contracted rigs are comprised of 286 AC drive FlexRigs and 1 3,000-horsepower SCR rig that was reactivated for ultradeep operations. Included in the 287 contracted rigs are 161 rigs under term contracts and 126 rigs in the spot market. Spot pricing has continued to slightly increase, and it is still about 5% lower as compared to pricing for rigs under term contracts, most of which were originally priced in even stronger markets during the last few years. As we transition into the third fiscal quarter, we expect revenue days to increase by about 7% quarter-to-quarter, along with relatively flat average rig revenue per day levels and relatively flat average rig expense per day levels. Regarding our U.S. land term contract backlog, we already have term contract commitments for an average of 157 rigs for the remaining 2 quarters of fiscal 2014 and an average of 110 rigs for fiscal 2015. The average quarterly pricing level for these contracted rigs is expected to remain relatively flat during the corresponding 6 quarters. Should spot pricing continue to improve, we would not be surprised if our total average rig revenue per day begins to slightly increase a few quarters from now. Let me now transition to our offshore segment, where segment operating income was approximately 5% stronger than in the prior quarter, and the average rig margin per day again exceeded our expectations at $27,665. Eight platform rigs remained active, and our ninth platform rig is now committed and expected to commence operations in fiscal 2015. As we look at the third fiscal quarter, we expect flat utilization levels in our offshore segment and a decline in the average rig margin per day to approximately $25,000, primarily as a result of a pricing adjustment on 1 of the 8 active rigs. The pricing adjustment will take place during the third fiscal quarter and after the rig finalizes the first phase of an ongoing project that required a significant upfront investment. This pricing adjustment is also expected to unfavorably affect our fourth fiscal quarter average rig margin per day by another few thousand dollars as compared to the third fiscal quarter. Additionally, we have continued to experience a strong contribution to our offshore segment operating income from management contracts on customer-owned platform rigs. The contribution during the second fiscal quarter was slightly under $5 million, and it is expected to decline to approximately $4 million during the third fiscal quarter and then increase to approximately $5 million during the fourth fiscal quarter. The quarterly contribution for management contracts may increase to $6 million or $7 million during fiscal 2015. I will now transition to the international land segment, where segment operating income declined by approximately $1.6 million as we experienced a lower level of activity during the second fiscal quarter as compared to the first fiscal quarter. Revenue days decreased by about 6% for an average of 22.6 active rigs. A rig in Tunisia and a rig in Colombia became idle during the second fiscal quarter. Nevertheless, the average rig margin per day increased by $576 to $10,919 during that same period. As of today, our international land segment has 22 active rigs, 13 of which are AC drive FlexRigs. Eight of the active rigs are in Argentina, 4 in Colombia, 5 in Ecuador, 3 in Bahrain and 2 in the UAE. A total of 7 rigs are currently idle in the segment, 3 of which are in Colombia, 2 in Tunisia, 1 in Argentina and 1 in Ecuador. In addition, one new rig is in transit to its first location in Colombia and one rig is in the process of moving from the U.S. to Mozambique. For the third fiscal quarter, we expect international land revenue days to be relatively flat as compared to the second fiscal quarter, and corresponding average rig margin per day is expected to be down by approximately 5% as compared to the prior quarter. Looking further ahead, the new 3,000-horsepower AC drive rig that is in transit to its first location in Colombia is expected to begin operations early in the fourth fiscal quarter. In addition, we expect 2 of the 10 rigs deploying to Argentina from the U.S. and the rig in transit to Mozambique to also commence operations before the end of the fiscal year. I will now transition from segment-related information to other important topics, including our revised capital expenditures estimate and our expected income tax rate for the rest of the fiscal year. Given today's announcement of an additional 9 new build commitments, other previously announced contracts and ongoing conversations with customers that may lead to additional FlexRig commitments, the company's new fiscal 2014 capital expenditures estimate increased from $950 million to $1.1 billion. This will provide significant flexibility in terms of our ability to deliver additional new builds during the first fiscal quarter of 2015. Approximately 60% of the revised CapEx estimate corresponds to our new build program, approximately 25% to maintenance CapEx and the remainder to other projects. The actual spending level may vary, depending primarily on the timing of procurement related to our ongoing new build efforts and actual maintenance capital requirements during the year. We still expect to be able to fully fund our fiscal 2014 CapEx program as well as other scheduled commitments from existing cash and from cash to be provided by operating activities during the fiscal year. Our effective income tax rate for continuing operations during the second fiscal quarter was reported at approximately 36.6%. This higher-than-expected effective tax rate for the quarter was primarily due to updated tax estimates for the year that no longer allow us to realign or take advantage of previously estimated excess foreign tax credits during fiscal 2014. We expect the effective income tax rate for the second half of fiscal 2014 to be between 34% and 35%, and the effective tax rate for all of fiscal 2014 to be approximately 35%. As it relates to our investment portfolio, the company sold 250,000 shares of its Schlumberger holdings for a total proceeds of over $23 million that favorably impacted earnings per share by approximately $0.12 in the quarter. Our remaining investment portfolio recently had a pretax market value of approximately $260 million and an after-tax value of approximately $160 million. Regarding other previously provided fiscal 2014 estimates, we still expect our annual depreciation expense to total approximately $500 million and general and administrative expenses to total approximately $130 million. Interest expense net of capitalized interest is expected to be in the range of $4 million to $6 million during fiscal 2014. That concludes our prepared comments. And Mike [ph], we will now open the call to questions, please.

[Operator:]

[Operator Instructions] And we'll go first to Robin Shoemaker with Citi.

[Robin E. Shoemaker:]

Juan Pablo, can you just explain again what led to the decline in average rig margin sequentially? And were you saying that you expect the average rig margin per day in the U.S. to be relatively constant for a few quarters going forward?

[Juan Pablo Tardio:]

I think your question regarding the margin relates to our transition from the first fiscal quarter to the second fiscal quarter going slightly down. And we had previously guided our average rig revenue per day to be flat to slightly down, and we did expect our average rig expense per day to be at $13,000 or probably higher as we spoke about it during the last conference call. So we weren't surprised to see that slight drop in average rig margin. As we go into the next several quarters -- so let me just suggest the June quarter -- as you know, we guided toward a relatively flat revenue per day numbers and relatively flat expense per day numbers which would yield approximately relatively flat margin per day results. So that's in general our expectation for June. As we see how the combination of our terms -- excuse me, of our rigs that are under term contracts and our rigs that are in the spot market and how that pricing works out in terms of total weighted average as rigs roll off of term contracts and as new builds are deployed, et cetera, there's a lot of moving variables there. So I just wanted to give you a sense in terms of what would happen if we continue to see the level of spot pricing go slightly up quarter-over-quarter at -- in that type of setting. And what we would expect and would not be surprised by is again, if we continue to see this slight trend of increasing pricing, is that the average rig revenue per day may slightly go up during the next -- I should rephrase that -- in a few -- during a few quarters from now -- or in a few quarters from now. So not in the June quarter, but perhaps in the September quarter, maybe in the December quarter, depending again on many moving variables. We hope that rig expense levels per day continue to be relatively flat. The assumption there would be, of course, if average rig revenue increases and average rig expense continues to be more or less flat, then yes, we would expect to have some increase in the average rig margins for the segment.

[Robin E. Shoemaker:]

Okay. And in terms of the 44 new builds that are under long-term contracts, is there any upward movement in the long-term contract rate in, let's say, in the -- ones you've sign recently of the 44 versus 6 months ago or 8 months ago? Is that term contract rate moving at all as the spot rate is?

[John W. Lindsay:]

Robin, this is John. Yes, the pricing is improving. The contracts that we've entered into recently have higher rates than what we had 6 months ago or so.

[Robin E. Shoemaker:]

Okay. And then if I may on the same topic on the new builds, is there with a -- any increase in new build cost either because of equipment costs or because you're going from 2 per month to 3 per month so maybe that would maybe slightly lower the cost, I'm not sure? But is there any upward trend at all in the costs of building a Flex 3 or a Flex 5 compared to last year?

[John W. Lindsay:]

Right. Well, if you're comparing on an apples-to-apples basis, the costs are relatively flat. We really don't see a -- what I'm thinking -- what I'm speaking to, Robin, is a standard Flex 3, say, without a skid system or without an additional higher pressure capability. It's going to be a similar type investment to what we've had over time. But we are -- again, FlexRig5s are a higher investment than a Flex 3 -- a standard Flex 3, so that investment is higher. As we have customers desire longer -- going from 100-foot skid system to a 200-foot skid system, adding 7,500 psi pumping systems -- all of those things drive the investment up. At the same time, we're getting a corresponding rate increase that's going to, again, keep our rates of return at the levels that you've been used to seeing as.

[Operator:]

And we'll go next to Byron Pope with Tudor, Pickering, Holt.

[Byron K. Pope:]

John, should we -- are we at the point in the cycle where we should expect to see your FlexRigs that are -- some of your FlexRigs that are currently working in the spot market start to get termed out? And if so, what's the nature of those conversations in terms of the tender of the term? Is it starting to push out further 1-year, 1-year plus? Just curious as to your thoughts on that.

[John W. Lindsay:]

Well, we're -- I guess we're slightly over 50% of the working fleet that's on term. I think probably a year ago, we were closer to 2/3 of our fleet that was term. So I wouldn't be surprised to see that -- from our perspective, I do think we'd be interested. We're not going to be interested in the 6 months. It's going to need to be, if I would think, longer than a year, a year to 2 years or I think other than that, we'd probably just assume -- just remain in the spot market. But I think it's reasonable to expect for us to maintain that 50% to 60% range of term contract to spot market. Does that answer your question, Byron?

[Byron K. Pope:]

It does. And it seems like your -- the strategy is to grow your U.S. rig count via new build FlexRigs. And so how do you think about the long-term strategy for the SCR rigs in your feet? Are those going to be opportunistic on the international side as opportunities arise? Just how are you thinking about those rigs?

[John W. Lindsay:]

Well, you noted that we do have -- we did put an SCR rig back to work. It's a 3,000 horsepower. We have 8 of those I believe in the U.S. today. Actually, I guess we have 7. 7 SCR 3,000-horsepower in the U.S. That's an ultradeep well that it's going to work on. I think there's the potential to have more of that type of work in the future. As far as the rest of the fleet, from our perspective, there's not customer demand for 1,200-, 1,500-horsepower SCR-type rigs. Obviously, our competitors are utilizing those rigs and growing their fleet in that capacity. From our perspective, again, at least from our customers, we don't see a demand from them or a desire for them to pick at one of our Flex 1s or Flex 2s, or one of our older SCR type of rigs. If you think about it from our perspective, too, is the SCR fleet -- our fleet is so small on a relative basis, percentage basis, compared to the rest of our operating fleet. When you hear us talk about the uniformity, the advantages of having a uniform fleet, the consistency that we're able to provide from a training, from supply chain, from a performance perspective, it really is the best [indiscernible] for us to think about putting those rigs back to work right now. I do think there are -- again, there's competitors out there that are putting SCR rigs back to work. There could be a situation where those SCR rigs could be sold to another contractor or be sold to international markets as a possibility. But at least from our perspective, we see far too many advantages to leveraging the uniformity of our fleet. We do see a lot of advantages there.

[Byron K. Pope:]

And last question for me. I think I heard -- of the 9 new build FlexRig contracts that you announced today, I think I heard 6 Flex 3s and 3 Flex 5s. Just curious as to the basin distribution of those and whether they'll -- all or most of them have skidding systems.

[John W. Lindsay:]

The distribution, 4 of the 9 are going to the Permian, 2 to the Eagle Ford, 2 to the Utica and 1 to the Haynesville. It's about a 50-50 mix on skid systems. If you were to look -- at it's interesting. If you look at the 44 that we've announced this fiscal year, if you're looking at about 60 -- or about 2/3 of those rigs have skid systems. But if you were to differentiate between the Permian and then all the other basins that I talked about that were working, the Permian has an average of about 40 -- about 40% of those rigs have skid systems, whereas those other basins are closer to 85%. And so I think what it is, it's an indicator of those other basins that are further along the path of development, the development phase of drilling and going more into pad drilling. And I think clearly, there are -- some of our customers in the Permian that are at that phase, but there's still a lot of customers out there that are still probably holding acreage and exploring to a certain extent. The great news, Byron, is all of those Flex 3s that don't have skid systems and we continue to build additional skid systems for Flex 3s in the fleet in addition to our new build, those rigs are all capable of having the skid package added at a later date, and that's been I think very successful for us and for our customers.

[Operator:]

And we'll go next to Kurt Hallead with RBC Capital Markets.

[Kurt Hallead:]

And so I just want to come back in and get a look at the U.S. land drilling dynamic, the fact that you have 95% plus utilization on AC class rigs. And yes, you have some other legacy rigs that may be adding to the marketplace but clearly, not satisfying demand completely. Your outlook on a relatively flat pricing and margin is kind of a head scratcher, I guess, given the tightness in the market. I know you gave some explanation a little bit earlier, but I don't know if something's not adding up. I'm just hoping that you might be able to try to add again, at least, for my benefit. Add a little color to why kind of just a flattish outlook when the market is just so tight. And you do have 115 rigs available to the spot market, so it's not like you're 80% contracted and you can't benefit from the spot market pricing. So what -- can you help me connect the dots here?

[John W. Lindsay:]

Yes, Kurt. This is John. I want to say a few things, and I was going to have Juan Pablo give a little more granularity. It's a great question, and we understand because it is a strong market. We are doing our best to get our spot market pricing back to the levels that it was in 2012 prior to the slowdown that we all saw. I think we're still approximately 5% or so away from that. It's interesting, Kurt, when you look at our average spot market day rates and our average term contract day rates today compared to other all-time highs, they're pretty much spot on. I mean -- so we are -- we do have some very -- what we will consider a very attractive pricing. We're continuing to price that up. But part of the challenge is -- and that's what Juan Pablo can give a little more color on -- is just when you consider all of the different variables associated with the different rig sizes and types and areas and rigs rolling off with term contract that drives that. So Juan Pablo, you might share or give a little bit more color on that.

[Juan Pablo Tardio:]

Sure. Kurt, I think the easiest way to understand it is to consider that the rigs in general that are in the spot market, as we mentioned earlier, were set in terms of pricing and stronger markets in general. And so what is happening is that as those rigs roll off of their term contract, their pricing is coming down to approximately where the spot pricing is today. And that dynamic provides a downward pull to the average, which is offset by what you mentioned. We're seeing an increasing trend in terms of pricing in the spot market, which offsets that downward pull that I just mentioned in terms of the term contracts.

[Operator:]

And we will go next to Tom Curran with FBR Capital Markets.

[Thomas Curran:]

John, since you opened the door, I'll step through it. What do you think your SCR rigs on average could command in the secondary market right now? And have you entertained any interest from potential buyers?

[John W. Lindsay:]

Well, we haven't sold -- obviously, we haven't sold the Flex 1 or Flex 2. We have sold some SCR rigs in the past 2 years or so that were -- horsepower ranges from 1,000 up to probably 1,500 and varying condition, and the range was probably a $3 million to $5 million, $3 million to $6 million range. It's really hard for us to say again. Without us being out there marketing those rigs, it's hard to say that. I mean, we're going to continue to evaluate our options on what we might possibly do. Again, what -- the point I made earlier, the great position that we're in as our idle SCR fleet is a very, very small percentage of our overall available fleet. We don't have any mechanical rigs. And so we're not having to be out there fighting to try to gain market share by investing additional dollars in those older rigs and trying to make them competitive. So -- and I mean, it's a great question. I don't have an answer for you right now. Again, I just -- I threw it out there as a possibility. I mean, we have been successful in selling some SCR rigs over the last couple of years. But if we could be successful going forward on these others, it's hard to say at this stage.

[Thomas Curran:]

Okay. Then shifting gears to the new build program. With the resurgence in incremental Tier 1 new build award flow we've seen since the start of the second half of 2013, you guys have reclaimed the lead in terms of your win rate of the awards that have been made to the big 4 land drillers. Why wouldn't you now go ahead and step up your speculative construction and take your cadence today to 4 rigs per month and start adding those speculative new builds to the queue?

[John W. Lindsay:]

Tom, I mean, again, that's a great question on your part. I think from our perspective, we lack the model that we've used over the years. We've been successful with it. One of the key advantages, of course, we have is our ability to scale our cadence up and then pull it back if need be. Obviously, for the first time that I can recall, last summer, when we didn't have new build pricing that would support new build contracts, we continued to build rigs at 2 a month, for our own account, for our spare capacity. And fortunately, the market responded and we were able to take advantage of that. But from just purely building on spec, I mean, we don't view it as that. Again, if you look at our fleet profile, we've got to have those spare capacity, that spare kit. If the demand gets to the level it needs to, we're going to be able to respond quickly. We've been able to do that in the past. You've seen us before go from 2 to 3 to 4 in a relatively short period of time. We could do the same thing here. So I think we're going to let the demand drive that. I don't think, Tom, that we're really giving up any material number of rigs by doing what -- versus -- doing what we're doing versus what you're suggesting, which is go ahead and kick it into 4 a month right now. I don't think we're really giving it anything.

[Thomas Curran:]

So no concerns about you seeing potential renewed erosion of pull position here by holding off on that?

[John W. Lindsay:]

Tom, I don't. Because, really, if you look at -- we've been estimating that for 2014, 80 to 100 new AC rigs would be built. Interestingly enough, we though last year, there would be 80. I think it ended up being less than 70. It turned out to be around 65. Well, we're thinking that now, it's probably 90 to 100 for 2014. I don't know what that spells for 2015 yet. But the other providers of AC rigs, I don't see a huge appetite on their part to really ramp up their production cadence, and so I don't know whether they have the capability or not. But I sure don't get the feeling that we're going to lose market share or our lead position by holding off at this stage of the game. Again, there may be some information out there that I'm not aware of, but I sure feel like that. We're in the lead, and we're well positioned and feel like we're going to be able to continue to maintain that.

[Thomas Curran:]

Last one for me. Moving south to Vaca Muerta, what's the earliest, timing-wise, we might see a renewed -- a follow-on tranche of awards, and what would be the potential size range for that next tranche?

[John W. Lindsay:]

Well, I think it would be very difficult to respond prior to 2015, and so I think that's what probably makes the most sense. I mean, as you heard earlier, we're essentially at 100% utilization of our AC fleet here. We've got 5 rigs in the U.S. that are idle now that are going in, and so that means there's additional 5 that are working that will go. And then we'll -- so -- and even from a new build perspective, that would be -- probably be hard to get that down. So it's going to be 2015. I think a 5 or 10 -- if we could add another 5 or 10 in 2015, I would -- I'd be really pleased with that. But again, you've heard me say before that my predictions on international growth had been off before, so it's just really not clear for us at this stage on what the size and the scope for 2015. We do know that it would be difficult to respond prior to 2015.

[Operator:]

[Operator Instructions] Then we'll go next to John Daniel with Simmons & Company.

[John M. Daniel:]

When you guys have mentioned that your contract coverage is 110 rigs for fiscal '15, that's including all of the contracted rigs that haven't been delivered yet, correct?

[John W. Lindsay:]

Yes, John.

[John M. Daniel:]

Okay. The average 157 contracted rigs for the next 2 quarters then dropped to an average of 110 for next fiscal year, so the drop-off in contracted rig is more rapid than the new builds that are being delivered? And you've got a 5% delta between contracted and spot revenue per day. So basically, until we see an -- call it a 5% improvement in the spot market, it's tough to see rev growth per day increasing if I kind of summarize that?

[John W. Lindsay:]

That's fair.

[John M. Daniel:]

Is that -- okay. And so if that's fair, then do you see that type of pricing leverage unfolding in the next 3 to 6 months in the spot market?

[John W. Lindsay:]

Well, John, it's hard to say. Again, I mentioned earlier we're trying to get our 5% or so back that we gave up. We've gotten some of that back. We'd like to get the rest of it back. And again, let's face it. It's a function of our customers, and it's a function of our performance. As much as we'd like to say it, I mean, really the customers are the ones that are driving this, both from a demand perspective and what they're willing to pay for a contractor's given performance. And so I think that's really what it's a function of, and I like our chances. I think we're in a great position to continue to capture some of that pricing back and hopefully, we'll be able to deliver that over the next couple of quarters.

[John M. Daniel:]

Okay, fair enough. I won't beat the dead horse. When you guys report average revenue per day of $28,000, how much of that revenue per day is not through day rate? Ballpark? $1,000, $500, $300?

[John W. Lindsay:]

Probably, it's a mixed bag in terms of each of the contracts that are out there. In average, it's probably around 5% to 10%, but that's just a rough estimate.

[John M. Daniel:]

Okay, that's fine. And then what type of rig is going to Mozambique?

[John W. Lindsay:]

That's a FlexRig3.

[John M. Daniel:]

Okay, all right. And then last one for me. Don't take this the wrong way, but do you have any payment protection built into the YPF contract, and are you going to be able to get cash out of the country?

[John W. Lindsay:]

Well, I think we've done a very good job in -- we obviously understand the risks, but I think we have as good a contract as we could expect to get. I'm pleased with that. And it's not risk-free. But again, we've worked in Argentina and other countries internationally for a long time, and so I think we've done a good job protecting ourselves. And I feel good about that.

[Operator:]

[Operator Instructions] And we'll go to Brad Handler with Jefferies.

[Brad Handler:]

Please forgive me if I'm retreading an old ground. I don't think I am, but it has been a -- there has been a lot of calls this morning. Question on operating costs. You guys have held -- it sounds like you've -- it seems like you've held your ground at the $13,000 a day range despite having a lot of rig moves. And I guess I'm curious if there's an opportunity or how you might describe the conditions if the rig moves slow, and do you think rig moves might slow that, that might allow for some operating cost opportunity?

[John W. Lindsay:]

Brad, this is John. I mean, it's a great question. I think your sense is right. There's a possibility of -- of course, there's always the other side, which is well -- what are other variables that have changed that we may not have great insight into at this stage of the quarter. I mean, obviously, if you look at previous quarters, there have been times that we've reported expenses at $12,000 or $12,700, $12,800, so that's possible. But we're continuing to deliver a lot of rigs, both new builds as well as moving rigs from basin to basin. Anytime that's happening, I'm always a little bit concerned about that. But overall, again, I'm very pleased with our people's work on getting the costs more consistent. They've worked very, very hard on it. They've worked on a lot of systems-type things that have been of help. So if we had our vote, we'd vote for yes. We'd vote for $12,700 or $12,800. But at this stage, I think $13,000 -- the range that we've guided to makes the most sense [indiscernible]

[Brad Handler:]

To give you some room, it sounds like, for other variables as you say.

[John W. Lindsay:]

I think that's -- again, I think it's fair. If you look at our expense per day trends over time, I mean, we've seen $1,000, $1,500 a day fluctuation. But if you -- again, if you look at our last 6 quarter average, it's right at $13,000 a day. And again, we had some that are higher, some that are lower. So it's a possibility that it could come in lower, but we're sure not expecting it.

[Brad Handler:]

Okay, got it. Maybe a separate question, and I have a feeling I'm starting to tread on ground that's been well trod on this call so, again, forgive me. But have you shared the spread between current term rates and spot rates?

[Juan Pablo Tardio:]

Yes, Brad. This is Juan Pablo. We mentioned that the pricing difference is still at around 5%. And that's -- that is an apples-to-apples comparison just to make sure that everybody's clear in terms of where we are in the market.

[Operator:]

[Operator Instructions]

[John W. Lindsay:]

All right. Well, if there are no other questions, Mike, thank you, everybody, for joining -- yes?

[Operator:]

Pardon the interruption, gentlemen. We do just have one more. It is Mike Breard with Hodges Capital.

[Michael Breard:]

I'm just wondering, you're holding flat rigs in the U.S. for a shipment in Argentina. Are you getting sort of a standby rate on that or quarterly mobilization moves?

[John W. Lindsay:]

Well, Mike, it's a little bit of a mixed bag because those rigs haven't all been sitting there idle. And there's this churn. You heard us talk about this in the past where we have a churn. Even though quarter-to-quarter, we may have had 12 or 15 or 18 AC rigs idle, it wasn't the same 12 or 15 or 18. There was a churn. And so what we've tried to do as best as we can is when rigs grow off of some contracts or off of the contract, those are the rigs that were pulling and going. Any standby time or anything like that is going to be built into the mobilization as far as in our bid. And you're just not talking about any material type of effect at all. But it's a great question. And we've done the best we can. I think our people have worked with our existing customers and figured out ways to make this happen.

[Michael Breard:]

All right. And if you put more rigs in Argentina in 2015, I guess, theoretically, it could be a mixture of new rigs and existing rigs.

[John W. Lindsay:]

I think it will be -- would potentially be difficult to make new build economics. We're -- in Argentina, I think it would be more likely that we will continue to send existing FlexRig3s and FlexRig4s. There are some additional demand for some of the smaller rigs as well. So that would be our expectations just from a new build economics perspective.

[Michael Breard:]

Okay. So they don't need quite as advanced a rig? I mean, they're not drilling the longer laterals and all the kind of stuff that we're drilling here in the U.S.?

[John W. Lindsay:]

Well, Mike, I wouldn't agree with that. What I would say is they're on the front end of developing that shale. And in fact, some of the wells that are being drilled, some are horizontal and some aren't. They're trending more towards horizontal. All of these rigs will have our skid system. So I think they'll likely have in the U.S., I think they'll start with -- I'm just going to throw a number out -- 4,000-foot laterals. And over time, they'll trend like we have trended here in the U.S. They'll get to 6,000, 8,000, 10,000-foot laterals. But obviously, there's a learning curve and it takes time to figure out on the frac side how to do things in the most efficient way. But these rigs that we're sending are advanced-technology Flex 3s. I mean, these rigs are going to drill wells down there as if we were sending a new build Flex 3. So we're sure not sending a compromised product at all. We're just sending an existing rig. Otherwise -- again, we couldn't do it with new builds and we couldn't do it because of the new build economics. But I think it's an attractive situation for us and for YPF. All right. Well thank you, everybody, for joining us and have a good day.

[Operator:]

And this does conclude today's program, ladies and gentlemen. We do appreciate everyone's participation. You may disconnect at any time.