Helmerich and Payne Inc (HP) 2014 Q4 法說會逐字稿

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.

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 US 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.

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 FY14. 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 US has accelerated the legacy rig fleet replacement cycle in US land, as a result of exploration and production companies' shift to drilling more complex horizontal wells.

During the past three years alone, the industry has built and deployed approximately 350 new AC drive rigs. And H&P has contracted and built approximately one-third of those new rigs, while our two largest peers combined have built one-third, and all the other contractors together built the remaining third. 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 over-building the AC rig fleet.

Now, with oil price levels at three-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 the evolving market conditions on incremental new builds and pricing are, at this point, hard to determine. Although a case can be made for US 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 new builds during that period, all sponsored with multi-year term contracts.

Another concern some investors pose is a narrative around a 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 six additional FlexRigs in the US, which drives our total to a record-breaking 89 new build FlexRigs contracted over the past 14 months, with 48 of those rigs already deployed.

Our FlexRig production cadence reached four rigs per month in September of this year, and we plan to continue that cadence at least through FY15. Also worth noting, 46 of the 48 delivery slots for FY15 have signed multi-year 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 we'll turn the call back to Juan Pablo, where he will you give you more details on fiscal Q4 numbers and our outlook for the next quarter.

Thank you, John. The Company's FY14 record level of operating income had 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 US land drilling operations delivered $276 million in segment operating income during the fourth fiscal quarter, excluding the impact of abandonment charges related to de-commissioned 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 nine de-commissioned rigs, the 333 available rigs in the US 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 idle rigs, 9 are AC drive FlexRigs, and the remaining 23 idle rigs are SCR rigs.

The nine idle AC FlexRigs are all smaller FlexRig 4M 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 2 are 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 nine rigs de-commissioned in September included all of the segment's SCR conventional rigs that had drawworks ratings of 2,000 horsepower or lower.

Looking at the first quarter of FY15, 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 a 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 US 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 FY15. 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 new builds are deployed. Should spot pricing remain flat through FY15 as compared to the fourth quarter average of FY14, 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 to the fourth quarter of FY14, 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 new builds 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 FlexRig3's and 10 are FlexRig5's.

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%. Eight 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 FY15, 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, continue 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 nine in Argentina, five in Columbia, three in Ecuador, three in Bahrain, two in the UAE, and one in Mozambique. Eight rigs are idle, including three in Ecuador, two in Columbia, two into Tunisia, and one in Argentina. An additional six rigs already assigned to this segment are in various stages of transition from the US 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 FY14, and we expect capital expenditures for FY15 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 FY14 total of $953 million was lower than expected, primarily as a result of on time and under budget delivery of new rigs during 2014, along with the timing of some spending that shifted to FY15. About 70% of the CapEx estimate for FY15 corresponds to our new build program, 20% to maintenance CapEx, and the remainder to other projects.

Net cash provided by operating activities was over $1.1 billion during FY14. Although we expect to generate an even higher level of cash from operating activities during FY15, 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 FY15, an average of 133 rigs during FY16, and an average of 100 rigs during FY17.

Approximately 90% of these rigs correspond to our US 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 FY15.

General and administrative expenses are expected to also increase, to slightly over $140 million. Our effective income tax rate for continuing operations during FY14 was reported at approximately 35.4%. We expect the effective tax rate for FY15 to be between 35% and 36%.

As in FY13 and FY14, we expect a continued deferral of income taxes during FY15, 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.

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 our the past three 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 Instructions)

Jeff Spittel, Clarkson Capital Markets.

Thank you. Good morning, gentlemen.

Good morning, Jeff.

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 [for] an acceleration in 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?

Jeff, 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 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, 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 write-ups here in the last couple of weeks that probably should expect to see a rig count reduction over through 2015. It seems to us that, 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 the comment about 2012 through 2013, and the subsequent rig count reduction of around 250 rigs. Now granted, 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 most reasonable. I think H&P is a very well positioned to weather a softening in the marketplace.

I don't see anything that would lead us to believe that it is 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 are able to respond more quickly with new builds, in the event that the market comes back and oil prices get stronger.

No, that makes sense. I appreciate that. And maybe with regard to your discussions with customers on incremental new builds. I would imagine, given that you're pretty full on your FY15 slated deliveries, that there hasn't been a discernible change, in terms of their appetite for term on potential new contracts?

The discussions that we've had ongoing are terms and rates that are similar to what we've had in the last couple dozen new builds that we've announced. But your sense is right.

Our next available is in the fourth fiscal quarter of 2015, at four rigs a month. And so when you're looking at a 9 or 10 month delay for the next new build, 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 new builds through that softening market.

Thank you for the time, guys. Appreciate it.

All right, Jeff. Thanks.

(Operator Instructions)

Kurt Hallead, RBC Capital Markets.

Hey, good morning.

Good morning, Kurt.

How quickly things change.

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

No doubt. No doubt at all.

So I'm curious, last few times that there has been some softness in the market, and E&P's adjusted their spending plans, there were some early terminations of contracts. So we'd like to get your 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 give us some sense on that? That would be great.

Right. At this stage, we've 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 one rig associated with that over -- I don't know -- the last month, or 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 this fleet that they have working. And I just would find it very hard to believe, at least in this pricing environment, that they would be early terminating rigs.

I don't think anyone is 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?

No, yes. That's helpful. Let me follow that up by saying -- yes, you mentioned you're going to maintain your new build cadence out through FY15. And I'm 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?

Kurt, all -- assuming -- at four rigs a month through the fiscal year, of course, 48 rigs, we have 46 of those 48 with multi-year term contracts, all with -- in the same range of returns and pay-backs that we've talked about over time. So we're very pleased with having that book of business. And again, it goes back to one of the themes of our discussion is, our ability to respond more quickly in these stronger cycles allows us to get our cadence up, and get that kind of a book.

So that's our intent is, we'll continue to build at four month through the fiscal year, because all of those rigs, with the exception of two, which are in the, I think, August/September timeframe. So they are in the fourth quarter. Those are the only two 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 new builds in the future.

[Right]. 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.

Right. And Kurt, you've heard us talk about our all-of-the-above approach, as it relates to capital, and we would 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 are 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.

Got it. Hey, appreciate that. Thanks.

All right, Kurt. Thank you.

Michael LaMotte, Guggenheim Securities.

Thanks. Good morning, guys.

Good morning, Mike.

Hey, John or Juan Pablo, how many Flex 4M's are there in the fleet?

We have 22.

22. Okay.

22 in the US, and 9 of those are idle today.

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?

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 I don't -- if we get that, we'll let you know a little later in the call.

Yes, it's only a few.

It's only a few, yes.

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 -- the labor side, I guess is a better general question?

Right. 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. (laughter) But obviously, with building four rigs a month, we have a need for personnel. So we won't be in a situation where we are laying anyone off, or anything like that.

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 --

Frictional unemployment.

Yes, exactly. Frictional unemployment. Rigs get re-leased, rigs get re-contracted, and we have that going on right now, just like we had before.

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

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.

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

Michael, I don't see that right now. Let's put it this way. I don't see that in the first fiscal quarter.

Okay.

And 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. 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 next couple of weeks, that many have published.

We think, in that event, that there is going to be a great opportunity for customers to high-grade their fleets. And 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.

Okay. Great. And 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, by my math, is 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?

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.

Okay. Great. Thanks, guys.

Thank you.

John Daniel, Simmons & Company.

Thank you. Hey, guys.

Good morning, John.

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

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, we 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 the bottom line, in terms of daily margins, from the Argentina project, as we've messaged before.

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, 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. And that has happened in past cycles. Not in a large way, but it has happened in past cycles.

Is that starting to happen now?

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, how low do they stay at these levels? But we have not seen any of that -- pardon me, John -- at this stage.

Okay. Last one for me, and it is back to you, Juan Pablo. I think you had 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?

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.

It's not new product-related?

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.

Okay. Thank you for your time.

Thank you.

(Operator Instructions)

Walt Chancellor, Macquarie Research.

Hey, good morning.

Good morning, Walt.

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

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.

Okay. So fair to say, the $1.4 billion assumes the current order book that you have? And the higher end would imply something higher?

I think that's a fair generalization.

Okay.

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.

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 new build 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?

Right. 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.

All right. Appreciate the color. Thank you.

Klayton Kovac, Tudor Pickering.

Good morning, guys.

Good morning.

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

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 one- or a two-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 those 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.

Okay. Thank you. And then just my second question, it's on the offshore guidance.

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?

No. The former. So we expect margins to be lower when we transition from one platform to another. So that creates the difference. Other considerations are, we may get into different types of day rates. Warm stack day rates, cold stack rig day rates, et cetera.

Okay. Thank you. I'll turn it back over.

Thank you.

Jonathan Sisto, Credit Suisse.

Good morning, guys. This is Jim Wicklund, I apologize.

Good morning.

Going -- 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 of 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 for an SCR, and wanted to start paying 26 for an electrical rig -- I meant modern AC rig, that they may have already done that.

And it seems to me that the replacement cycle, when it gets like this -- 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 a downturn to actually occur?

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 over 15% today. We gave up anywhere between 5% and 10% in the spot market, in terms of pricing.

We continue to contract new builds through that period of time, not all of it, granted. But in the softest part of the market that, in the summer of 2013, 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 --

I agree. We don't know yet. Yes.

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 one 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 --

The efficiency. No question.

So there's the efficiency aspect, but you know what? As there is 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 it. Again, we're just -- we're giving you an example of, in several --

I know. And --

Larger cycles --

And (multiple speakers) -- 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. (multiple speakers) Let me ask one more thing, if I could --

Yes. Go ahead.

Your $15,000 day to OE margin, what is the highest, John, you've ever seen?

Is that it?

I think in 2006, 2007 we may have had some spot market. But if you look at it in average, since going back to --

When we were younger. (laughter)

Three and four -- when we were younger, and our memories were a little better. I think probably, we've probably been at 15.5, 15.6 range.

Okay. And then -- 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, and it 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 quicker replacement. Thanks, guys. I appreciate it.

All right.

Thank you, Jim.

Stuart Lipp, ARBC Global.

Hi, guys. Could you talk about the safety of the dividends? And first of all, I didn't hear you 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 was accelerating last few years. And I wonder, with a softer environment and so on, whether you would see next year being a peak for capital spending?

Stuart, this is Juan Pablo. Let me start to address your questions, and just remind me if I missed 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 increases.

We -- given the cyclicality and the nature of our business, we don't think about payout ratios that would create a lot of cyclicality around those dividend payments. So we think about dollars per share, and we -- the intention is to continue to sustain or increase those levels going forward.

Of coarse, 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 FY15. Did I address your questions?

Yes. Absolutely. And it was reassuring to hear you talk about the dividend that way. Thank you.

Thank you.

David Wishnow, GMP Securities.

Good morning, guys. I was wondering if you could give us an idea of how many of those FlexRig 4M's which are currently working are contracted through FY15?

Of the 13 that are active today, 6 are on term contract, and 7 are in the spot.

Okay.

And I believe most of the six go through FY15.

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, hottest spec assets out there?

It's a great question. There's -- 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 two or three 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, we're successful in doing that.

I don't know of any stranded rig class, or anything like this. The Flex 4M's are really a function of a shift away from vertical drilling to horizontal, and particularly longer horizontal-type wells.

Okay. Got it. Thank you. Appreciate it. I'll turn it back.

Thank you.

(Operator Instructions)

John Daniel, Simmons & Company.

Hey, guys, thanks for putting me back in. John, of all the new builds that you got coming over the next 12 months, are they all for the US market?

Yes.

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

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

Okay. Great. Thank you very much.

All right, John. Thank you. All right. We may have time for one more question. Mike, please?

I am showing no further questions in queue.

(Operator Instructions)

And gentlemen, I am showing no further questions.

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

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.