Helmerich & Payne, Inc.
Q4 2014 Earnings Call Transcript

Published: 13 Nov 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to today's program. [Operator Instructions] Today's conference will be recorded. At this time, it is my pleasure to turn the conference 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 fourth quarter and fiscal year-end of 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 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 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.

[John W. Lindsay:]

Thank you, Juan Pablo, and good morning, everyone. The company is pleased to report all-time record annual levels of revenue, operating income and drilling activity for fiscal 2014. These achievements are possible because of the dedication and hard work of our employees, and I would like to take this opportunity to thank each of them for their contributions to our success. The energy revolution in the U.S. has accelerated the legacy rig fleet replacement cycle in U.S. land as a result of exploration and production companies' shift to drilling more complex horizontal wells. During the past 3 years alone, the industry has built and deployed approximately 350 new AC drive rigs. And H&P has contracted and built approximately 1/3 of those new rigs. While our 2 largest peers combined have built 1/3, and all the other contractors together built the remaining 1/3. With more contractors planning new rigs for delivery in 2015 at a higher cadence than they have in past cycles, many investors have been concerned about overbuilding the AC rig fleet. Now with oil price levels at 3-year lows, there is greater uncertainty about near-term drilling activity. While it is not yet clear how the next few months will unfold, the actual effects of evolving market conditions on incremental newbuilds and pricing are at this point hard to determine. Although a case can be made for U.S. land drilling activity to continue to be resilient, we believe H&P is very well prepared for a softer market if that is the outcome. Recall the market slowdown in late 2012 through the fall of 2013. The industry rig count dropped approximately 250 rigs, and H&P was able to increase market share from 12% to 15%. And we were successful in adding a significant number of newbuilds during that period, all sponsored with multiyear term contracts. Another concern some investors pose is a narrative around the narrowing gap between our peers and H&P's competitive rig offerings. Questions like, "How fast are others catching up?" The questions are reasonable and intuitive, after all we have led the industry for over 10 years in the advanced technology rig space. While we certainly established a first mover advantage, our differentiation is more than the rig offering. We have combined an impressive record of continuous improvement with several competitive advantages. The company's competitive advantages are a very strong combination of customer service reputation, fleet quality, term contract coverage, customer base and financial strength. I'd like to spend a few minutes and dive into a few more details regarding these competitive advantages, beginning with exceptional customer service at H&P, a result of our people and their desire to deliver customer satisfaction and value to the customer. Customer service is an important part of our culture. Our employees, those on the rigs as well as those that provide the organizational support to the FlexRigs, take great pride in providing the best service in the industry. The H&P fleet quality, another competitive advantage, we design and build our FlexRig fleet. We have the largest, most modern and uniform fleet of AC drive rigs in the world. We have accumulated over 1,400 rig years of AC drive learnings that help make us better every day. The fleet uniformity allows us to be more effective in terms of safety, training, supply chain and performance while driving value for our customers. And we don't have to worry about investing capital in a legacy fleet of rigs like many of our peers in an attempt to keep up with advanced technology rigs. Term contract coverage is an advantage, especially in a soft oil price environment. Approximately 60% of our active fleet is under term contract today. And with our current commitments, an average of over half of our active fleet is already under term contract for 2015. In addition to the term coverage, the quality of the contract is important. As approximately 75% of our term-contracted rig years are with large investment-grade exploration and production companies. Customer base is a competitive advantage as well. Over 75% of our rigs are working for large exploration and production companies, with investment-grade balance sheets and core acreage positions in the unconventional resource plays. We've also been successful in expanding our new customer base each year as more E&P companies expand their horizontal drilling programs. And finally, the competitive advantage of the financial strength at H&P. Our conservative balance sheet approach provides access to ample liquidity, supporting our growth opportunities through the cycles. Furthermore, we are pleased to have significantly grown our dividend over the past few years in keeping with the company's enhanced position to return cash to shareholders. We have also repurchased shares at opportunistic times through the cycles. We will continue to hone these competitive advantages as we move forward in our objective to create value for both our customers and shareholders. So after 10 years of industry leadership, how are we doing today? We believe we are stronger than ever. And we are pleased to report contracts to build and operate 6 additional FlexRigs in the U.S., which drives our total to a record-breaking 89 newbuild FlexRigs contracted over the past 14 months, with 48 of those rigs already deployed. Our FlexRig production cadence reached 4 rigs per month in September of this year, and we plan to continue that cadence at least through fiscal 2015. Also worth noting, 46 of the 48 delivery slots for fiscal 2015 have signed multiyear term contracts. And we continue to have conversations with customers regarding new FlexRigs. The ability to respond to customer demand and ramp up our rig manufacturing cadence more quickly than our peers allows us to take advantage of strong market conditions, and we expect this advantage to continue. Now I will turn the call back to Juan Pablo where he'll give you more details on fiscal Q4 numbers and our outlook for the next quarter.

[Juan Pablo Tardio:]

Thank you, John. The company's fiscal 2014 record level of operating income at approximately $1.1 billion represents an increase of over 10% as compared to the prior year. And the corresponding record level of drilling activity at an average of 306 globally active rigs during the fiscal year represents a similar increase over the same time frame. We also announced a record level of 83 new FlexRigs with attractive long-term contracts during the fiscal year. Our quarterly operating activity also continued to grow at the end of the fiscal year. Following are some comments on each of our drilling segments. Our U.S. land drilling operations delivered $276 million in segment operating income during the fourth fiscal quarter, excluding the impact of abandonment charges related to decommissioned rigs and other used drilling equipment. The number of revenue days increased by about 3% from the prior quarter, resulting in an average of over 291 active rigs during the fourth fiscal quarter. Approximately 174 of these rigs were active under term contracts and approximately 117 rigs were active in the spot market. The average rig revenue per day slightly increased to $28,164. And the average rig expense per day also slightly increased to $13,170, resulting in an average rig margin per day of $14,994. As of today, and excluding the 9 decommissioned rigs, the 333 available rigs in the U.S. land segment include 298 active rigs, 32 idle rigs and 3 inactive rigs that are currently being prepared for transition to the YPF Argentina project. Of the 32 idled rigs, 9 are AC drive FlexRigs, and the remaining 23 idle rigs are SCR rigs. The 9 idled AC FlexRigs are all smaller FlexRig4M-type rigs in West Texas that are well suited for vertical wells and for shallower horizontal wells, but not designed to drill the more challenging, longer-lateral horizontal wells that are becoming more prevalent in the Permian. The 298 active rigs are comprised of 296 AC drive FlexRigs and two 3,000-horsepower SCR rigs. Included in the 298 rigs that are active today are 179 rigs under term contracts and 119 rigs in the spot market. The 9 rigs decommissioned in September, included all of the segment's SCR conventional rigs that had drawworks [ph] ratings of 2,000 horsepower or lower. Looking at the first quarter of fiscal 2015, we expect revenue days to increase by about 1% to 2% quarter-to-quarter. We expect our average rig revenue per day level to remain flat with a bias to a very slight upside. The average rig expense per day level is expected to slightly increase to roughly $13,250, partly as the result of rigs transitioning across regions as we reposition them in more attractive markets. We do, however, continue to expect a potential variance of a few percentage points given the slightly volatile nature of quarterly expenses. Regarding our U.S. land term contract backlog, we already have term contract commitments for an average of 177 rigs for the first quarter and a total average of over 160 rigs for all of fiscal 2015. The average quarterly pricing level for these rigs that are already under term contracts is expected to steadily increase by up to 1% to 2% during the fiscal year as some rigs roll off and newbuilds are deployed. Should spot pricing remain flat through fiscal 2015 as compared to the fourth quarter average of fiscal 2014, we would expect our total average rig revenue per day for the segment to also remain relatively flat. The quarterly average pricing for rigs in the spot market slightly increased from the third through the fourth quarter of fiscal 2014 and is expected to continue to slightly increase in average during the first fiscal quarter. Nevertheless, spot pricing today is still a couple of percentage points lower as compared to pricing for rigs now working under term contracts negotiated over the last few years. Of the 15 contracted newbuilds announced since our last conference call in late July, 7 are going to the Permian, 4 to the Oklahoma Woodford, 2 to the Eagle Ford and 2 to the Tuscaloosa Marine Shale. Furthermore, 11 of the 15 have skidding systems suitable for multi-well pad drilling, and of these 15 rigs, 5 are FlexRig3s and 10 are FlexRig5s. Let me now transition to our offshore operations. Segment operating income declined from approximately $17 million to $15 million. The average rig margin per day declined to $22,385, and utilization remained flat at 89%. 8 platform rigs were active in the quarter, and our ninth platform rig commenced operations after the end of the fiscal year. As we look at the first quarter of fiscal 2015, we expect revenue days to increase by approximately 10%, along with a decline in the average rig margin per day to approximately $20,000. The expected lower daily margin is mostly a result of some platform rig maintenance considerations. We do expect some of our rigs to transition from platform to platform during the rest of the fiscal year, which will probably not impact utilization but is expected at this point to have a negative impact on our average rig margin per day during the following quarters, potentially bringing that average to levels under $20,000 per day. The timing, however, is not yet determined, and the full impact will also depend on evolving market conditions. We plan on providing more clarity during the coming quarterly conference calls as more information becomes available. Management contracts on platform rigs, however, continued to more favorably contribute to our offshore segment operating income. Their contribution during the fourth fiscal quarter was approximately $4 million and is expected to increase to $6 million or more during each of the following quarters. Moving on to our international land operations. Segment operating income reduced to approximately $6 million during the quarter. The average rig margin per day declined to $8,769, and quarterly revenue days slightly increased to an equivalent of about 23 active rigs. As of today, our international land segment has 23 active rigs, including 9 in Argentina, 5 in Colombia, 3 in Ecuador, 3 in Bahrain, 2 in the UAE and 1 in Mozambique. 8 rigs are idle, including 3 in Ecuador, 2 in Colombia, 2 in Tunisia and 1 in Argentina. An additional 6 rigs are -- already assigned to the segment are in various stages of transition from the U.S. to Argentina. For the first fiscal quarter, we expect international land revenue days and the average rig margin per day to be relatively flat as compared to the fourth fiscal quarter. As mentioned during our prior conference call, we believe that the margin weakness in the segment is temporary due to several rigs in transition. The first rig related to our 10-rig YPF project has already commenced operations. And the other rigs are in process of moving, with the last rig to spud in the third quarter. We would expect to see roughly 400 revenue days from these rigs during the second fiscal quarter and hopefully, twice as many during the third fiscal quarter. Their daily rig margins and contribution to the bottom line are also expected to improve as this long-term project is fully deployed during the fiscal year and transitional expenses are behind us. I will now comment on other corporate level details. Our capital expenditures totaled $953 million during fiscal 2014, and we expect capital expenditures for fiscal 2015 to be in the range of $1.4 billion to $1.7 billion, depending primarily on market conditions and incremental demand for additional new FlexRigs during the fiscal year. As was the case in the prior year, the fiscal 2014 total of $953 million was lower than expected, primarily as the result of on-time and underbudget delivery of new rigs during 2014, along with the timing of some spending that shifted to fiscal 2015. About 70% of the CapEx estimate for fiscal 2015 corresponds to our newbuild program, 20% to maintenance CapEx and the remainder to other projects. Net cash provided by operating activities was over $1.1 billion during fiscal 2014. Although we expect to generate an even higher level of cash from operating activities during fiscal 2015, we may need to externally fund a portion of our capital expenditures during the fiscal year. With a debt-to-cap ratio today of approximately 2%, we look forward to the possibility of taking advantage of our financial strength and increasing our debt level to help fund the company's continued organic growth. Especially considering that we have already secured customer commitments to sponsor the construction of 46 new FlexRigs during the fiscal year, all with attractive long-term contracts. Including these and other commitments, we already have secured term contracts for an average of approximately 180 rigs across our drilling segments during fiscal 2015, an average of 133 rigs during fiscal 2016, and an average of 100 rigs during fiscal 2017. Approximately 90% of these rigs correspond to our U.S. land segment and provide the company with the benefit of an average pricing level that is expected to generate rig margin per day averages that are higher than those reported in the segment during our most recent quarter. Given the continuing growth of our fleet, we expect our total annual depreciation expense to increase to slightly over $600 million during fiscal 2015. General and administrative expenses are expected to also increase to slightly over $140 million. Our effective income tax rate for continuing operations during fiscal 2014 was recorded at approximately 35.4%. We expect the effective tax rate for fiscal 2015 to be between 35% and 36%. As in fiscal years 2013 and 2014, we expect a continued deferral of income taxes during fiscal 2015 related to depreciation of property and equipment. As it relates to our investment portfolio, the holdings remain unchanged as compared to the prior quarter. And with that, let me turn the call back to John.

[John W. Lindsay:]

Thank you, Juan Pablo, and prior to opening the call for questions, I want to close with a few comments regarding the confidence we have in our longtime strategy for growing shareholder value. We will continue to focus on innovation, technology and systems at the rig site as well as those offsite functions that support the FlexRig value proposition. We will continue to invest in technology to drive safety improvements for our people, operational efficiencies for customers and attractive economic returns for our shareholders. With the swift move in oil prices over the past 3 months, we are reminded of the cyclical highs and lows that our industry experiences. It is in times like these we are thankful for our experienced management team and seasoned field operation coupled with the best assets in the industry to navigate the challenges and respond to customers' needs. This is another reason, we believe, as the energy revolution evolves, we will remain positioned to lead the legacy rig replacement cycle. And now, we'll open the call for questions.

[Operator:]

[Operator Instructions] And we'll go first to the side of Jeff Spittel with Clarkson Capital Markets.

[Jeffrey Spittel:]

Maybe if we could start, John. It sounded like from your commentary, if we are entering a period here maybe in calendar 2015 when E&P spending appetites are a little bit softer, it sounds like your expectation is that would manifest itself in a acceleration of the replacement of, say, the 500 or so legacy rigs that are drilling horizontal wells rather than necessarily seeing rate and utilization pressure for FlexRigs on the spot market. Is that a fairly accurate read?

[John W. Lindsay:]

Well, Jeff, it's -- I mean, it's a great question. Let me set the -- begin by setting the context. It wasn't that long ago, we had our last quarterly call. And of course, we've had subsequent meetings with the investors and investment community. And during that time, oil prices were in that $90 to $100 range. And of course, the question -- the next question was always, well, what type of pricing level would it have to get to in order to see a change in behavior or see less activity. And of course, our answer was in the $75 to $80 range, and of course, that's where it is today. We're not seeing -- we haven't seen anything from our customers in terms of changes in behaviors, but it just seems reasonable that -- and of course, there's been a lot of writeups here in the last couple of weeks, that probably, we should expect to see a rig count reduction over -- through 2015. Well, it seems to us, to make sense, that the rigs that would be most impacted and that would be impacted in the most -- in the quickest fashion would be the older legacy fleet. I think there's -- it seems like around 800, about 800 older rigs, SCR and mechanical rigs, that are drilling horizontal and directional wells today. And there's probably been close to 200, 150 to 200 of those rigs that have been reactivated over the last 12 months or so. So to me, that seems reasonable. I made a comment about 2012 through 2013 and the subsequent rig count reduction of around 250 rigs. Now granted -- and oil prices got below $80, but we also had a pretty soft natural gas environment at that time too, if you recall. But it seems to me that that's the most reasonable. I think H&P is very well positioned to weather a softening in the marketplace. I don't see anything that would lead us to believe that it's going to be a dramatic pullback. And then I think we're also well positioned in the event that oil prices were to strengthen. And we're able to respond more quickly with newbuilds in the event that the market comes back and oil prices get stronger.

[Jeffrey Spittel:]

And that makes sense. I appreciate that. And maybe with regard to your discussions with customers on incremental newbuilds. I would imagine given that you're pretty full on your fiscal 2015 slated deliveries that there hasn't been a discernible change in terms of their appetite for term on potential new contracts.

[John W. Lindsay:]

Well, the discussions that we've had ongoing are terms and rates that are similar to what we've had in the last couple dozen newbuilds that we've announced. But your sense is right. Our next available is in the fourth fiscal quarter of 2015 at 4 rigs a month. And so when you're looking at a 9 or 10 months delay for the next newbuild, the appetite isn't like it was before. But again, we've seen, and we actually saw it in 2012, 2013 where we did contract newbuilds through that softening market.

[Operator:]

[Operator Instructions] We'll go next to the side of Kurt Hallead with RBC Capital Markets.

[Kurt Hallead:]

How quickly things change, huh?

[John W. Lindsay:]

It changes in a hurry. That's the cyclicality of our business that we always talk about, isn't it?

[Kurt Hallead:]

No doubt. No doubt at all. So I'm curious, the last few times that there's been some softness in the market and E&Ps kind of adjusted their spending plans, there some early terminations of contracts. So I would like to get your kind of perspective on how you guys are looking at that and how many rigs might be exposed to that. Or if you can do some comparison and contrast to prior period early termination dynamics and just give us some sense on that, that would be great.

[John W. Lindsay:]

Right. Well, at this stage, we have not seen any early terminations associated with the oil price environment. The early terminations that we've seen are -- have all been related more to a shift from vertical drilling to horizontal-type drilling, and it was -- and we've had 1 rig associated with that over, I don't know, for the last month or the last couple of months. I haven't seen any indication of that. From my perspective, our customers and the operators in general, they've spent a lot of time and effort and money to develop the fleet that they have working. And I just would find it very hard to believe that this -- at least in this pricing environment, that they would be early-terminating rigs. I don't think anyone is kind of out over their skis in terms of having too many rigs under term contract. I just don't get that sense at all. So does that answer your question?

[Kurt Hallead:]

No -- yes, that's helpful. Let me follow that up by saying, well, yes, you mentioned you're going to maintain your newbuild cadence out through fiscal '15. And I'm kind of curious that given the reduced oil price environment, is that just a function of having to deliver on what you already contracted? Or is there any flexibility that you could reduce that cadence as you get into the year?

[John W. Lindsay:]

Well, Kurt, all -- assuming -- well, at 4 rigs a month through the fiscal year, of course, 48 rigs, we have 46 of those 48 with multiyear term contracts, all with -- in the same range of returns and paybacks that we've talked about over time. So we're very pleased with having that book of business. And again, it kind of goes back to one of the themes of our discussion, is our ability to respond more quickly in the stronger cycles allows us to get our cadence up and get that kind of a book. So yes, that's our intent, is we'll continue to build 4 a month through the fiscal year because all of those rigs, with the exception of 2, which are in the, I think, August, September time frame, so they're in the fourth quarter, those were the only 2 slots that aren't committed. We haven't decided after the fiscal year what our cadence will be. Again, I think it's still really early. It's too early to make a call at this stage, and I wouldn't be surprised to see -- again, we have conversations that are ongoing now with customers, so I wouldn't be surprised to see additional newbuilds in the future.

[Kurt Hallead:]

And then if I could finish up with just this last one. Again, can you give us some update on how you guys determine allocation of cash between, obviously, building new assets vis-a-vis maybe buying back stock or increasing the dividend, especially in light of the fact that the stock is now down 8% today and obviously well off the high point that it hit in the middle of the year?

[John W. Lindsay:]

Right. Well, Kurt, you've heard us talk about our -- kind of all-of-the-above approach as it relates to capital, and we'd prefer to continue to invest in new FlexRigs and grow the fleet organically. But I think we've had an awfully strong track record of dividends and of course, increasing dividends over the last couple of years. We have had share buybacks. We've been opportunistic in the way that we've approached that. So I think, from our perspective, it's all on the table. We're obviously not in a position today to talk about what our plans are going to be, but we're going to look for opportunities to return cash to shareholders.

[Operator:]

And we'll go next to Michael LaMotte with Guggenheim Securities.

[Michael K. LaMotte:]

John or Juan Pablo, how many Flex4Ms are there in the fleet?

[John W. Lindsay:]

We have 22 in the U.S., and 9 of those are idle today.

[Michael K. LaMotte:]

Okay. Totally unrelated, in the prepared comments, it was mentioned that a few of the new contracted rigs are going to the Tuscaloosa Marine Shale. How many rigs will you have in that play? And what's the contract coverage look like there?

[John W. Lindsay:]

We'll look that up. I will mention, I believe, of the 89 we've announced, 5 of those are going to the Tuscaloosa Marine Shale. I do think we have a couple that are working in the spot market. But if we get that, we'll let you know a little later in the call.

[Juan Pablo Tardio:]

Yes. It's only a few.

[John W. Lindsay:]

It's only a few, yes.

[Michael K. LaMotte:]

Only a few? Okay. And then for rigs that do come down, even if it's just a handful, what do you do with the crews on those rigs? How do you manage through the cycle of the labor side, I guess, is a better general question?

[John W. Lindsay:]

Right. Well, I don't know whether this is a good thing or a bad thing, but we have a lot of experience in doing that over the years. But obviously, with building 4 rigs a month, we have needs for personnel. So we won't be in a situation where we're laying anyone off or anything like that. I mean, we'll be in a great position to place people, assuming that we see that. Right now, we have some rigs that have been released, that have not become idle. But that's really part of the standard course of our business. We've talked about that over time. There's just a level of rig...

[Michael K. LaMotte:]

Frictional unemployment.

[John W. Lindsay:]

Yes, exactly. Frictional unemployment, rigs get released, rigs get recontracted, and we have that going on right now just like we have -- we had before.

[Michael K. LaMotte:]

Okay. So nothing over and above that at this point?

[John W. Lindsay:]

Well, we have -- there's a handful of rigs that have been released, and a few of those that have gotten contracts, and there's some that haven't had contracts. And so that's part of our -- as we're looking at our expenses, we -- there's the potential, if the market continues to soften, there's a potential that we could stack some rigs. So there's some expenses associated with that as well.

[Michael K. LaMotte:]

Okay. I know that in other -- or in 2012, for example, you took advantage of idle time and mobilization time to actually do some maintenance and preventive maintenance on rigs. Is there any chance that expenses might go up not because of stacking but because of accelerated maintenance?

[John W. Lindsay:]

Michael, I don't see that right now. Let's put it this way. I don't see that in the first fiscal quarter. That would be something that we would message if that were a need in the second fiscal quarter or third fiscal quarter. Again, that's not our expectation. I mean, we really think, again, if it is a case where we see 150 to 200 rigs pulling back again, that's not our prediction, that's just what we've read over the last couple of weeks that many have published. We think in that event that there's going to be a great opportunity for customers to high-grade their fleets. And I mean, if you think about how many older rigs have been put out, just look at the SCR and the mechanical rig count, it's gone up over the last year. And so you would think that those older assets are going to be more likely to be laid down. And then, again, I think it's an opportunity for high-grades for customers.

[Michael K. LaMotte:]

Okay. Great. Last one for me. Just to follow up on Kurt's question quickly about cash return and buybacks. Juan Pablo, you mentioned adding some debt this year. I'm curious, if you would do that short-term just to effectively cover the capital needs, which is like, by my math, just a few hundred million dollars. Or whether you'd do something more substantive in the markets, a note deal that would give you some capital to make some repurchases this year.

[Juan Pablo Tardio:]

Yes, Michael. We are, as you can imagine, exploring all of the options at this point. The expectation is that we will need, as we mentioned, some external funding for the fiscal year. But that will depend on CapEx and other considerations, the ones that you mentioned as well. We will just have to work through that throughout the year. We don't have any immediate needs, but we do expect to be working on that throughout the fiscal year.

[Operator:]

And we'll go next to John Daniel with Simmons & Company.

[John M. Daniel:]

Juan Pablo, maybe this is for you, but can you tell us what the cost per day is that you're incurring in international where the rig moves? And then just in an all-else-being-equal world, can you sort of range-bound for us what margins would be once the rigs are delivered and operating?

[Juan Pablo Tardio:]

I wish I could have a number for you, John. That is a number that we'll continue to monitor. These types of transitions, as you know, have several different types of expenditures associated with them. It's difficult to get the timing exactly right. Unfortunately, we will see some costs as you mentioned. As we transition through the fiscal year, once all of the rigs that are going to Argentina are fully deployed and contributing to the bottom line in the way that we expect, we do expect significant increases as compares to the $8,000 to $9,000 per day levels in terms of margins that we're seeing today. What that number will be, I couldn't tell you exactly. Of course, it will also depend on other moving parts as we move into the year. But we do expect significantly higher contributions to bottom line in terms of daily margins from the Argentina project as we've messaged before.

[John M. Daniel:]

Okay. John, under your contracts, do you allow customers to sublease the rigs if they don't need them? And if so, does the E&P customer have to notify you before the rig is subleased?

[John W. Lindsay:]

John, there are some assignment provisions in the contract. And yes, there are -- we would be involved in that. There is an approval process that H&P has in that. So yes, I mean -- and that's happened in past cycles, not in a large way, but it has happened in past cycles.

[John M. Daniel:]

Is that starting to happen now?

[John W. Lindsay:]

No. We haven't seen any behavior change from our customers at this stage. But again, back to looking at it in the context of having oil prices as low as they are, I think the question is, is how low do they stay at these levels. But we have not seen any of that at this stage.

[John M. Daniel:]

Okay. Last one for me, and it's back to you, Juan Pablo. I think you said about 10% of the CapEx budget is on other projects. Can you give us -- that's a lot of money. I'm just curious if you can give us any color on what those other projects might be?

[Juan Pablo Tardio:]

It's a combination of many different things that includes yards -- facilities as we grow our fleet and our support structure around the country, things of that nature.

[John M. Daniel:]

That's not new-product-related?

[Juan Pablo Tardio:]

No, not necessarily. We have some additional equipment that we may be adding to existing rigs, but that depends on market demand and the type of equipment that is required, but that's about it.

[Operator:]

[Operator Instructions] We'll go next to Walt Chancellor with Macquarie Research.

[Walter Chancellor:]

So on the 2015 CapEx range, I just want to hone in on what the big swing factor is there. Is that additional long lead time items? If newbuild demand looks good for 2016, I guess, what's really driving that range?

[Juan Pablo Tardio:]

This is Juan Pablo, Walt. We are not sure how the conversations with customers regarding additional new FlexRig contracts will evolve. But we are prepared to potentially increase the number of FlexRigs that we deliver during the year. And so if that were to happen, that would drive us to the higher end of that range.

[Walter Chancellor:]

Okay. So fair to say the $1.4 billion assumes sort of the current order book that you have and the higher end would imply something higher.

[Juan Pablo Tardio:]

I think that's a fair generalization. As you know, we have, and as John mentioned, we have 46 of the 48 slots already committed and so we would not be surprised given the right market conditions to receive additional orders. And so we're providing that level of flexibility.

[Walter Chancellor:]

Okay. Great. And then I guess, for John, I think you may have covered this, but you've mentioned there have been no behavior changes from customers. But are you seeing any interest from your customers and maybe deferring some of the newbuild deliveries a little bit? And how would you all approach that? Would that even be an opportunity to perhaps maybe squeeze some customers in that don't want to be at the back of a 12-month queue?

[John W. Lindsay:]

Right. Well, again, we haven't had a change in that. We have seen that in the past. We have seen in previous cycles that customers have had delayed deliveries by a few months or so, I don't remember the details in the past. Again, we're not seeing that today. That is a possibility. And then your other point is, I guess, there's always that situation, probably less likely that you would be able to slide somebody into a slot. But I guess, that's always possible.

[Operator:]

And we'll go next to Klayton Kovac with Tudor, Pickering.

[Klayton Kovac:]

So during this last quarter, the U.S. land rigs that rolled off-contract, how many were re-upped on term contracts versus going to work on a well-to-well basis?

[John W. Lindsay:]

Klayton, I don't think we have those numbers here in front of us. My sense is it was a mix. I don't know that it was a 50-50 mix. But typically, we're going to see a mix of those -- some of those rigs going back into a 1- or a 2-year type of a contract. And then there's going to be a certain number that are just going to go -- roll into the spot market. It's interesting because in the spot market contracts, a lot of times, that rig will continue to work for that same customer for several years. It's just working under a well-to-well type contract. But I don't have those numbers in front of us.

[Klayton Kovac:]

Okay. And then just my second question, it's on the offshore guidance. I realize your margins are being affected in fiscal Q1 by maintenance. And then during the rest of the year, you're expecting margins to potentially go under the $20,000 a day. But utilization isn't expected to be impacted. So is this drop through the year caused by the rigs being on a lower rate as they transition from platform to platform? Or is it that market rates are going lower?

[Juan Pablo Tardio:]

No. The former. So we expect margins to be lower when we transition from 1 platform to another. So that creates the difference. Other considerations are we make it into different types of day rates, warm-stacked day rates, cold-stack, red day rates, et cetera.

[Operator:]

And we'll go next to Jonathan Sisto with Crédit Suisse.

[James Knowlton Wicklund:]

This is Jim Wicklund, I apologize. I understand that you guys are the best-positioned for a downturn, and I got all that. But the idea that we're going to accelerate the replacement older rigs, and that's usually what happens in a down cycle, it just strikes me if all these guys wanted to quit paying 18 or 19 per an SCR and wants to start paying 26 for an electrical rig, I meant modern AC rig, they may have already done that. And it seems to me that the replacement cycle, when it hits like this, and then I realize you guys don't have any equivalent third- and fourth-generation offshore rigs but it still impacted the day rates for the sixth-generation rigs, so don't day rates have to slide a little bit for that replacement cycle of older rigs in the downturn to actually occur?

[John W. Lindsay:]

Well, Jim, you've been at this a long time and so I know you know a lot about the business. I guess the most recent example would be, and again I used -- I talked about that in my comments, 2012, 2013. So in that case, the rig count came off 250 rigs. We picked up market share from 12% to 15%. We still have 15% -- over 15% today. We gave up anywhere between 5% and 10% in the spot market in terms of pricing. We continue to contract newbuilds through that period of time, not all of it, granted, but in the softest part of the market, that in the summer of '13, we didn't, if you recall. But again, if oil prices remain low or go lower over a longer period of time, then you have to expect that spot pricing will be affected. I think it's too early at this stage of the game to make that decision. But back to -- if you think about it in terms of 800 older rigs working, and I realize these rigs have upgrades and I realize a lot of these rigs have top drives, but it isn't a Tier 1 rig and it isn't -- it can't perform in the same way that an AC rig does. And so the day rate is obviously important, but Jim, what's most important is the well cycle time, the total cost of the well as it relates -- and so there's the efficiency aspect. But you know what, as there's a lot of moving parts and a lot of variables and it's not as easily drawn up and described as what we've tried to do, again, we're just -- we're giving you an example of -- in several larger cycles, we've seen this...

[James Knowlton Wicklund:]

No, no. And my question was more of a market question than a question specifically for you guys because I realize your insulation. So mine was more of a market question, but you answered it. Let me ask one more thing, if I could. Your $15,000 a day daily margin, what's the highest, John, you've ever seen? Is that it?

[John W. Lindsay:]

I think in '06, '07, we may have had some spot market. But if you look at it in average, since going back to 3 or 4, when we were younger, and our memories were a little better, I think probably, we've probably been at $15,500, $15,600 range.

[James Knowlton Wicklund:]

Okay. And I realize John that we don't know enough yet and I think you guys are being very rational about the outlook. And to your point, remaining flexible is the key. Mine was more of an industry question, and like I say, I understand that the new rigs are more efficient, but that doesn't always lead to quick replacement.

[Operator:]

And we'll go next to Stuart Lippe with RBC Global.

[Stuart Adam Lippe:]

Can you talk about the safety of the dividend? And first of all, I didn't hear you, I mean, give any kind of range of earnings for 2015. Did you? And did I miss that? And do you have a certain policy in terms of payout ratio? And also, how much -- do you see capital spending going down again in 2016? Because it seems like it's accelerating in the last few years, and I wonder with a softer environment and so on, whether you would see next year being kind of a peak for capital spending.

[Juan Pablo Tardio:]

Stuart, this is Juan Pablo. Let me try to address your questions, and just remind me if I miss any of that. We do not provide earnings guidance for the year. So no, there's nothing out there that we would have said for 2015. In terms of our dividends, we've been increasing our dividends for over 40 years every year. And so when we make decisions regarding increases, we certainly think about sustainability of that and potential continuing increase. As we've -- given the cyclicality and the nature of our business, we don't think about payout ratios that would create a lot of cyclicality around the dividend payment. So we think about dollars per share and we -- the intention is to continue to sustain or increase those levels going forward. Of course, there may be conditions in the mid- to long term that do not allow us to continue to do that, but nonetheless, that is the general intent. As it relates to CapEx or expenditures in 2016 going down, that may very well be the case. But this market, as you know, turns in a hurry and who knows, market conditions in 2016 may be very strong and our CapEx levels might be even higher than what we expect for fiscal 2015. Did I address your questions?

[Stuart Adam Lippe:]

Yes, absolutely. And it was reassuring to hear you talk about the dividend that way.

[Operator:]

And we'll go next to David Wishnow with GMP Securities.

[David A. Wishnow:]

I was wondering if you could give us an idea of how many of those FlexRig4Ms, which are currently working, are contracted through fiscal '15?

[John W. Lindsay:]

Of the 13 that are active today, 6 are on term contract and 7 are in the spot. And I believe most of the 6 go through fiscal '15.

[David A. Wishnow:]

Okay. And is there another class of assets you guys have in your fleet that's currently working, or maybe some of the older rigs, which would potentially be at risk in a downturn scenario because they're not the newest, highest-spec assets out there?

[John W. Lindsay:]

Well, it's a great question. There's -- I probably can't go into the details on the call, but I think the simplest answer is, I don't believe so. Again, as I look at the release notifications that we've had over the last 2 or 3 months, it's really in line with what we've seen over time. You get some rigs released and then you go out to the market and market the rigs to customers, and you end up getting them contracted and in most cases, that we're successful in doing that. I don't know of any stranded rig class or anything like this. The Flex4Ms are really a function of a shift away from vertical drilling to horizontal and particularly, longer horizontal-type wells.

[Operator:]

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

[John M. Daniel:]

John, of all the newbuilds that you got coming over the next 12 months, are they all for the U.S. market?

[John W. Lindsay:]

Yes.

[John M. Daniel:]

Okay. And then do you happen to have handy how many of your rigs right now are drilling vertical wells?

[John W. Lindsay:]

I think we have it. I believe it's close to 5% or so.

[Operator:]

I'm showing no further questions in queue. [Operator Instructions] And gentlemen, I'm showing no further questions.

[John W. Lindsay:]

Thank you very much, Mike. And thank you, everybody. Have a good day.

[Operator:]

And thank you for joining us today, ladies and gentlemen. We certainly do appreciate everyone's participation. You may disconnect at any time, and have a great day. Thank you.