Good day, everyone, and welcome to today's program. [Operator Instructions] Please note, this call may be recorded. I will be standing by should you need any assistance. It is now my pleasure to turn the conference over to Mr. Juan Pablo Tardio, Vice President and CFO. Please go ahead, sir.

Thank you, Justin, and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the fourth quarter and fiscal year end of 2013. With us today are Hans Helmerich, Chairman and CEO; and John Lindsay, President and COO. 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 Hans Helmerich.

Thank you, Juan Pablo. Good morning. We are pleased to have posted all-time record earnings and revenues for the company's year-end results. It's a credit to our folks that they achieved this milestone during a year when the overall land drilling industry experienced activity declines and lower day rates. Looking back over the year, we estimate the industry delivered around 80 new AC drive rigs to the domestic market. These rigs predictably pushed the lower performing rigs to the sideline and now, represent nearly 50% of rigs working today in unconventional basins. As this percentage continues to grow, we often receive questions from investors related to a narrative around a narrowing gap in terms of competitive overall rig offering in the land drilling space. The questions are fair and intuitively make sense. Some impending parity over an 8-year period should be expected. I say 8 years because, in 2005, our largest competitor announced a counter-offensive of the new build effort and we no longer had the AC drive rig market to ourselves. Not surprisingly, others followed. And eventually, nearly 11 years after the Flex 3 AC drive debut, every sizable land contractor, including a couple of startups, were talking up the virtues of their AC rig offering. In our thinking, after years of enjoying a first-mover advantage, the greater challenge was to focus our efforts to establish a sustainable one. Our conviction was that the customer would differentiate and pay for outstanding field execution, improving efficiencies and ongoing innovation and performance enhancements. Our people throughout the organization have delivered on each one of these, and our financial results over the years have reflected their success, as the FlexRig remains today the rig of choice. Our 2013 fiscal year performance provides an additional test case for how we are doing in…

Thank you, Hans. As announced earlier today, the company reported a record level of $957 million of operating income of for fiscal 2013. We also reported record levels of $737 million of net income and $3.4 billion of revenue for the fiscal year. Our capital expenditures totaled $809 million during fiscal 2013, and our corresponding estimate for fiscal 2014 is $850 million. The fiscal 2013 total of $809 million was lower than expected as a result of underbudget delivery of new rigs during 2013, along with the timing of some spending that shifted forward to fiscal 2014. Over 1/2 of the $850 million CapEx estimate for fiscal 2014 corresponds to our new build program, approximately 1/3 to maintenance CapEx and the remainder to tubular and other process[ph] . Net cash provided by operating activities was approximately $1 billion during fiscal 2013. We expect, at this point, to be able to fully fund our fiscal 2014 CapEx program, as well as other scheduled commitments from existing cash and cash -- and from cash to be provided by operating activities during the fiscal year. Our confidence in our ability to do this is enhanced by the fact that we already have secured term contract commitments for an average of approximately 148 rigs during fiscal 2014 and 81 rigs during fiscal 2015. Approximately 90% of those rigs correspond to our U.S. land segment and provide the company with the benefit of an average pricing level that, as described during our last conference call, is about 5% to 10% higher than current spot market pricing. Moreover, as some of our rigs that are under term contracts roll off these contracts and as announced new builds are deployed under new term contracts, we expect the average pricing of remaining rigs that are currently under term contract to slightly increase during fiscal 2014. As reported in our consolidated financial statements, depreciation expense for fiscal 2013 was approximately $456 million. Given the continuing growth of our fleet, we expect our total annual depreciation expense to increase to approximately $500 million during fiscal 2014. General and administrative expenses are expected to slightly increase to approximately $130 million. And interest expense after capitalized interest is expected to increase, but remain under $10 million during the fiscal year. Our effective income tax rate for continuing operations during fiscal 2013 was reported at approximately 35.3%. We expect the effective tax rate for fiscal 2014 to be between 35% and 36%. Also, similarly to fiscal 2013, we expect only a modest deferral of income taxes during fiscal 2014. As it relates to our investment portfolio, the holdings remain unchanged compared to the prior quarter. I will now turn the call over to John, and after John's comments, we will open the call for questions.

Thank you, Juan Pablo, and good morning, everyone. While many industry observers are uncertain regarding a meaningful improvement in the U.S. land rig count for the coming months, the industry's AC drive rig count has continued to march higher. In fact, over the past 12 months, the AC rig count is up approximately 120 rigs, while the combined SCR and mechanical rig count is down over 130 rigs. The reason for this replacement cycle is well known. E&P companies are drilling a larger percentage of unconventional horizontal wells, and the complexity factor of unconventional wells is much higher than a vertical well. In addition to greater well complexity, E&Ps are also expecting enhanced efficiencies from contractors. And that is the reason why advanced technology AC drive rigs, and specifically, the industry leader, FlexRig, should continue to grow market share. Customers continue to be results-oriented, and there is a differentiation in performance across all rig types. We believe our results demonstrate that H&P is the best positioned to lead this replacement cycle. We are convinced we have the best personnel, technology and systems that provide the reliability and efficiencies customers are looking for. Now I will make a few comments regarding each of our operating segments, and I'll begin with our U.S. land activity. The quarter was better than expected, with approximately 245 average active rigs as a result of improving market conditions. An average of approximately 156 rigs were active under term contracts, while an average of approximately 89 rigs were active in the spot market. Average rig revenue per day also exceeded expectations during the quarter and increased to $29,058 a day. Early termination revenue accounted for approximately $740 (sic) [$730] per day in the fourth fiscal quarter. Average rig expense per day was higher than expected and increased…

Thank you, John. And Justin, we will now open the call for questions.

[Operator Instructions] We'll take our first question from Robin Shoemaker.

My question, John, would be just in terms of the strength you're seeing in spot and term prices for FlexRigs, we're see -- I guess, we're seeing that overall kind of a flattish rig count. And so what would you, I mean, attribute the strength you're seeing in spot and term rates today? Is it in anticipation of stronger demand or -- so kind of what's your outlook for the overall rig count?

Okay, Robin. Well, overall and historically, in this business, we've focused our attention on the industry, the overall industry rig count. It was a much better barometer, I think, of demand than what it is today. And Hans and I both have tried to address that in -- when you consider the premium end of the market, if you consider the AC drive section of the market and if you look at the overall utilization of AC rigs in U.S. land, even though there's between 70 and 80 rigs stacked today, the utilization is still 90% or so. So there's a pretty clear level of pricing power that's there. I mean, as evidenced by new build announcements, I think there's an opportunity, and we've seen, I guess, over the last 60 days or so, 90 days -- 60 or 90 days or so, we've seen more of the spot market price firm and we've actually seen a little bit of pricing power. So I think that's why we see it. And again, I know it's -- when you look at the overall rig count trending sideways, it's hard to see that there would be pricing power. But I think if you look at the premium end of the market, that's where we see the pricing power.

Right. Okay, understood. So now in terms of your success in holding down or, actually, possibly lowering operating costs of rigs, is this tied into the greater prevalence of pad-type drilling? More -- less downtime, more efficient utilization related to pad drilling? Or other factors?

Rob, I don't want to make certain -- I understand your question. You were talking about our costs like over the last 12 months?

Yes, just the holding down of cost escalation on a daily operating per rig basis.

Well, we really haven't considered the pad drilling aspect necessarily, at least what we've seen, on our cost controls. I would say our cost controls are more a function of our systems and our processes that we've had in place or that we have in place and that we've improved, and our people's focus on that. Because whether we're drilling on pads or whether we're drilling on single-well locations, the fact is the rigs are working much harder today than a rig has ever worked. I mean, the lateral links, the hydraulic horsepower requirements, the cycle times. Sure, I think there would be -- there could be an argument to be made that if you're moving the rig less frequently with trucks, there's going to be some savings in costs. But I think, at least for us, I'm speaking for H&P, I think our cost effectiveness has been more a function of our process improvement and our uniform fleet, the fact that all we're working are Flex 3s, 4s and 5s. I think, that's really what drives our efficiencies.

And we'll take our next question from Jim Wicklund from Credit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Hans, John, Juan Pablo and to your entire company, I don't usually do this, but you guys are a class act and congratulations on setting a record in a year where nobody would have expected it. So from the industry perspective, you guys are a class act. Good job. My question, if I could, you guys recently won a platform contract with Shell. Can you tell us about that?

I'm going to have John tell you about it. I wanted you to pause after that comment, and just let us kind of enjoy that a little bit. That was nice, Jim. Thanks.

Jim, I fell out of -- well, thank you. And I fell out of my chair when you said it, so I'm trying to recover. What was your question again? James Knowlton Wicklund - Crédit Suisse AG, Research Division: You guys recently won a platform contract, I understand, with Shell, an offshore platform contract, is that right? Did I hear this right?

That's right. Well, Jim, it's probably a pretty solid rumor, but at this stage of the game, we can't talk about it much. We'll have more clarity on our next call in January. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Typically, how big are the platform contract jobs that you do? What size horsepower rigs are those?

They're 3,000 horsepower is most of what we're looking at. James Knowlton Wicklund - Crédit Suisse AG, Research Division: And can you just give us a ballpark idea generally of what 3,000-horsepower platform rig day rates are? Just broadly.

Well, yes, it's in line with what we have. It's probably high $50,000, low $60,000-a-day range.

And we'll take our next question from Ryan Fitzgibbon from Global Hunter.

First one for me is on your contracting strategy at this point. Your spot exposure has gone up a bit, I imagine that coincides with better pricing in the spot market. Can you talk about how you expect your spot exposure to trend going into '14 given, I would expect, some of the operators are looking to lock in rigs, first? And then second, can you quantify how spot market rates actually change quarter-on-quarter for you guys?

Ryan, this is John. I'll talk a little bit about the spot market. I'm going to have Juan Pablo address your last part of your question. You're right, our percentage of spot market rigs is higher than it has been trending over the last couple of quarters. I would expect to see our -- I would expect to see more of the spot market -- some of the spot market rigs rolling to term contracts. As far as our strategy, we're going to -- we're really going to do what the customer's demands are. I mean, if they're wanting to enter into term contracts, then we're going to be willing to do that. Obviously, if you look at it historically, we've been satisfied in that -- kind of that 50-50 range. Over the last year or so, I think we've been higher, where it's been 2/3 and 1/3. So we're going to be comfortable in that 50% to 65% range. We're not really concerned about it one way or the other. But I do think with the market tightening little bit, I would expect to see more of the spot market rigs going into term.

And this is Juan Pablo. To your question regarding spot market rates and how those have evolved. As you know, at the beginning of the year, we saw a little softness there and we had a slight decline since then. From the June quarter to September quarter, we experienced a very slight decline in pricing and average revenue per day for rigs in the spot market. Going forward, we hope that, that changes. Our expectation is for spot pricing, in general, to be slightly up, or flat to slightly up. There are other moving variables as well in terms of where those rigs might be working and what kind of pricing structure -- cost structure there might be in different regions. But in general, we expect a positive movement in terms of spot pricing going forward.

And Juan Pablo, I believe, in your opening remarks, you said 5% to 10% discrepancy there. Is it safe to assume, given the 12% discrepancy in the June quarter, it's at the high end of that 5% to 10% range right now?

Yes, I wouldn't describe it as a discrepancy. I would just describe it as the difference between the pricing of our rigs that are under term contract and the pricing of our rigs that are in the spot market. And so as we see what we have in terms of results for the September quarter, it's fair to describe that the difference between those 2 categories is approximately 5% to 10%. As you can imagine, and as I think we have mentioned in the past, there are other considerations related to the mix of where the rigs are working and what type of rigs are under term and what type of rigs are in the spot market and so forth. But I don't want to get into much of that. It's way too many things that move, many variables that move at the same time. But in general terms, hopefully again, what we see is, going forward, that gap in terms of pricing, apples-to-apples pricing that is, start to reduce into fiscal 2014.

Got it, makes sense. Second question for me is on international bid opportunities. I believe, in last quarter's call, you mentioned there's a couple of tenders out in the Middle East you were looking at. Just help me to get some color as to how that's progressed throughout the quarter, maybe where your outlook is for 2014 on new build opportunities internationally.

Ryan, we're still participating in tenders, both in South America and in the Middle East, and we don't have anything to announce at this stage. Our hope is that we'll be successful on some of those tenders. As compared to the U.S. market, the international market moves quite a bit slower. But we're hopeful that we'll have something. It's hard to say if it's going to be in the first part of 2014. I mean, we have all -- we would have all believed that our international activity would be higher than it is right now with the success we've had with FlexRigs working internationally, from an efficiency and safety perspective. But that's really all we have to update right now. We're upbeat about it. It's just moving fairly slow.

[Operator Instructions] And we'll take our next question from Brad Handler from Jefferies Securities.

Maybe I'll start with day rates also, and I admit as I ask this question and probably it's going to feel to you like it's more to do about very small moves than anything else. But if you laid out maybe an academic mathematical process for us a quarter or 2 ago around rates, given your commentary today and given some of the positive stepping -- some of the positive hints that you're giving about rates, is that profile for how the average day rate through '14 progresses? Does that change? Does it become a little less flat to down modestly, a little more flat, say, for example? I'm just trying to pick up on where you're taking us.

Thank you, Brad. This is Juan Pablo. You're exactly right. It was a comment based on a theoretical scenario, an academic-type scenario of what happens if everything else remains more or less equal and stock pricing remains flat through fiscal 2014. What might that do to the total average revenue per day in the U.S. land segment? And the answer to that was, well, it probably would impact it so that we would see a reduction of 1% to 2% or a couple of percentage points. I think that theoretical scenario is still true today. Of course, we could lay out a different scenario, and that scenario being what happens if we have spot pricing increase 5% to 10% to match what we have of our rigs under a term contract price, and how would that impact the total average revenue per day for fiscal 2014. And I think that the, again, theoretical answer to that scenario would be that we would see the opposite. We would see an increase of 1% to 2% in terms of our average revenue per day. Does that address your question, Brad?

It does. It looks like you thought about that question, so that's helpful. Let me shift gears, please. There is something that I'm unfamiliar with and I'd love to understand it better. Although John didn't mention it in his prepared comments, you mentioned that the revenue per day in the fiscal fourth quarter was, I guess, positively impacted by customer-requested delivery delay fees. So I don't know if that wound up not being a big part of it, since John didn't mention it. But to the degree that it is, I'd like to understand that a little bit better. What are the dynamics there? For example, there's -- I assume the contract start has pushed out. That sounds like the purpose. Is it the same term? Does the rate get impacted? How prevalent is this in your contracts, et cetera?

Brad, this is John. It's not very prevalent in terms of a percentage. As we think back really since 2008, 2009, we've had examples where customers have delayed deliveries. It doesn't happen very frequently. There is some compensation associated with the delay. And that's really -- I didn't feel like it was enough of a percentage of what we do to address it in the detailed comments. I thought the press release handled it very well. So it's not a very prevalent situation, particularly in a market like this, where it continues to be fairly strong.

Okay. I suppose that addresses it, but before I just drop it all together, is there any hint in seeing it of whether it's a function of the customer seeing even greater efficiencies and therefore needing a little less rig? Is there a way to generalize some of the driver behind what you've seen here? Or perhaps you could attribute it to something else?

I don't know the specifics. I don't think it's necessarily a function of efficiencies and having too many rigs. I guess it could be as it relates to a budget. But again, it's just part of a budget function that the customer has that they want to delay activity. And this is a U.S. land and an international situation. It's not just U.S. land.

And we'll take our next question from Brian (sic) [Byron] Pope from Tudor, Pickering. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just one question for me, John. I was struck by your commentary about your down -- being down to 15 idle AC rigs, just given that it seems as though most of this calendar year you've been kind of bouncing around between 18 and 20 idle AC rigs. And so I guess the comment I was struck by was when you had mentioned 9 of those 15 idle AC rigs are already committed for work. So I was just hoping you could speak to the progression of when those 9 rigs go to work? Because it almost feels to me like you're getting the sense from E&P operators that, once again, to Q1 of next year your utilization is going to be fairly tight. So was just wondering if you could comment a little, provide some incremental color on when those rigs go back to work.

Byron, that is -- what we were trying to express is, you're right, it's been over -- well, between 18 and 22 rigs since the third quarter call in '12. And again, we've made the point on previous calls, it's not the same 20 rigs. There's a churn that's going on. And I think on the last call, we had commented that it appeared that there were less rigs. And maybe it wasn't on the last call, maybe it was in some of our conferences in September and October. But there's just less customers giving rigs back to us. We're still putting rigs to work, but there's less rigs that are getting released. And so I think that's what we're seeing and so clearly, the demand has improved. We're seeing fewer customers releasing rigs, they're hanging onto their high-performing AC rigs. And we're in a position where we just have a handful of AC rigs that are available as existing rigs in our spot market. So we see that as a positive, and again, I think it could speak to a little bit more pricing power for us -- for us and others in the industry. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And I think the way you've characterized it before is the idle rigs you've had have been spread across basins. So is it fair to think that this subtle shift in the mentality among E&P operators is fairly a broad -- across basins?

Yes, we have been pleased. I mean, overall, we've had some nice contracting strength in really all of the basins. Clearly, Permian is a lot more active than any other basin. But yes, we've been pleased with getting nice response from all of them. So there -- we're seeing rigs in all the basins going back to work.

And we'll take our next question from Doug Becker from Bank of America.

John, I want to hone in a little bit more in the Permian demand. You indicated H&P could be close to 60 by the second quarter, with upside to that number. What kind of upside are we talking about, particularly in the context of maybe infrastructure constraints and still a very low level of pad drilling taking place in that basin?

You're right on the pad drilling, Doug. I think there's less than 20% of the wells out there are being drilled off a pad. So there's a lot of opportunity to improve. The 60 number that we've put out there is really just taking the new builds that are out there. We're having to assume that the current rigs are going to continue to work. We're obviously assuming that oil prices remain strong and we don't have a pullback anywhere, but -- so yes, we could see it at 60. But what you're seeing in the Permian at the same time is the Permian rig count's not -- the overall Permian rig count's not drilling. You've got your vertical rigs going down, your lower-end rigs being stacked. And so the question is, much like the overall industry rig count, what kind of a trade-out ratio happens? What kind of replacement ratio happens? Is it 1 for 1 or is it 1 for 1.5, whatever it may be. So it's difficult to really predict where the rig count is going. I think, it's going to be driven largely by the unconventionals and the horizontal rig count.

So if I understand what you're saying, not expecting a big increase in the overall rig count, just a continuation of that shift to the horizontal and presumably, H&P taking some additional market share in that context?

Yes, I don't see how -- I don't -- I'm not aware, at least, that the vertical rig count for the lower end of the market in the Permian is going to do anything but -- Permian, the low end of the rig count's going to continue to reduce, best I can tell. And customers are going to want to drill more horizontal wells and the rigs out -- a lot of rigs out there just aren't qualified, capable of doing that type of work.

Got it. And then Hans, just what would you need to see to accelerate the cadence of 2 new builds per month? Obviously, an improving market, but do you need to actually have a contract in hand? Or would you build a little bit in anticipation of that, given just the philosophy of and flexibility of using those -- that equipment ultimately for spares if a contract doesn't materialize?

I think, the 2 rig-per-month cadence that we have now, and we're talking about extending through the rest of our '14 fiscal year, is a good baseline. And the so I don't think we would reach for additional cadence without market demand and kind of a demand pull-through. So we like the conversations we're having today and some of the things we've talked about on the call. So I think, that's the approach we're taking.

[Operator Instructions] We'll take our next question from Mike Breard from Hodges Capital Management.

Just out of curiosity, how many customers are you working for now in the U.S. versus, say, 6 months ago or 12 months ago?

Mike, I want to say our rig -- our total customer count is right at 50. I think that's right in the U.S. And that's probably up 10 customers over the last year. We've added quite a few new customers. We've had quite a few new customers in the Permian and the Eagle Ford. And several of those are smaller customers, smaller E&Ps. So that's been encouraging. As you know, most of our customers, a large percentage of our customers are majors and large independents. So it's been nice to do more work for some of the smaller independents.

Okay. And then one last question, is your profit margin pretty much the same basin-by-basin? Or is there a significant difference anywhere?

Mike, this is Juan Pablo. In general, what happens is that we attain the same type of returns for new builds that go to different regions. But the difference might be related to what type of rigs are used in different regions. If we have, for example, a larger rig like a FlexRig5, we're going to have a larger day rate and a larger margin corresponding to that rig in order to yield the same level of returns that we expect, as Hans mentioned, given the higher level of investment. For areas where the need is for a much smaller rig, then the margins might be smaller in terms of cash margins. But in general, again, based on returns, I think they're equivalent, generally speaking.

Okay, but 1 rig at 1 basin will be about the same as a similar rig in other basin?

Yes, sir.

And we'll take our next question from Brad Handler from Jefferies.

Juan Pablo, maybe directed at you, a question about the CapEx. Are you comfortable splitting out how much capital is carrying into fiscal '14 from fiscal '13 that's driving the lower-than-expected CapEx number for fiscal '13?

In general terms, I'll be glad to do that. We had an $890 million estimate for fiscal '13 and the result was $809 million, as I mentioned earlier. And most of the difference between those numbers resulted from the shift in spending from one fiscal year to the other. At least I gave you some [indiscernible]

Exposure is more than half, right, so -- okay. If I think about it -- I would love to -- go ahead.

As I mentioned also earlier, most of the rest was related to being under budget in terms of the construction of our new builds, which, again, was a great achievement internally, and we thank our people involved in the process for that.

Understand. And I suppose, in fairness, that's what I was trying to get after in thinking about that structurally going forward. So in a way, I felt like I was sort of handing you an opportunity to describe that for us to some degree, but can I think about, I don't know, I guess I'll press you, is most -- can I think about 3 quarters of that shift being pushing things back into fiscal '14? Am I in the right ballpark?

Yes, as I mentioned, I'd prefer not to be that detailed in responding to that.

[Operator Instructions] And there appears to be no further questions.

Okay. Well, thank you very much, and good day to everybody.

Thank you.