Helmerich & Payne, Inc. (HP) Q2 2012 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to today's Second Quarter Earnings Conference Call. [Operator Instructions] Please note this call is being recorded. And it's now my pleasure to turn the conference over to Mr. Juan Pablo Tardio, Vice President and CFO. Please go ahead, sir.

Thank you, and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the second quarter of fiscal 2012. With us today are Hans Helmerich, Chairman and CEO; and John Lindsay, Executive Vice 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 reports 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's 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.

Thanks, Juan Pablo. Good morning, everyone. As we discuss our quarterly results and update our outlook going forward this morning, we will tackle the issue of increased operating expenses. But first, it may be helpful to revisit a couple of theme from our comments from our previous quarterly call in January. We posed this question then of how much downward pressure would plummeting natural gas prices, overflowing storage and growing production bring to bear upon the domestic land drilling market. We spoke of this transition of rigs being redirected from dry gas targets to oil and liquid-rich targets, suggesting then that the gas-directed rig count will even now likely accelerate its decline trend. Well, that has certainly occurred and we know how the rest of the winter and early spring was the warmest since 1895, and gas prices proceeded to fall to 10-year lows. In response, customers have been more determined to rotate and redirect their rig rosters away from dry gas efforts. As we expected, higher performing Tier 1 AC drive rigs are best positioned to make the transition, but it won't be totally seamless as it drive some transitional expenses higher. For those rigs under the contractors, very little impact from being redirected and transitioned. In fact, we're fortunate to have a very high percentage of our U.S. land active fleet, 67%, currently under long-term contracts. That number remains strong over the next 2 quarters, with an average of 157 rigs under term contract. On the other hand, for rigs on the spot market, the transition at times can involve a new customer and a new basin and incur additional costs, which can include crew retention, some mobilization costs, and often, additional maintenance items. So if a rig experiences some idle time between customers, costs are incurred as we hold on to most of that crew and use the opportunity to perform needed maintenance on that rig. That said, while the accelerating rotation contributed to this quarter's surprisingly higher average daily cost, it was one of several factors. We expect that as we mentioned on our last call and then later updated, costs to return to a range somewhere above the $13,200 per day number. That number increased to $13,826. But if you take a slightly broader perspective when comparing our first 6 months of fiscal 2012 with the last 6 months of fiscal 2011, average costs are up $244, a more modest increase than when you compare just the last 2 quarters. Also beyond some transitional cost increases, we are seeing cost pressures on several fronts. Some higher costs are driven by the steady march of more complex and challenging drilling and faster cycle times. For example, from 2010 to 2011, our average footage per day increased over 10%. Already in 2012, we have seen average footage per day increase another 10%. So on one hand, our performance continues to improve, but at the same time, simply more is being demanded from the rig. We will manage the challenge in a manner that plays to our strengths. Our success is securing premium margins that's relied on consistently reducing the customer's well cycle time. So first, we will continue to focus on safety, delivering performance efficiencies and repeatability to the customer. We have found over the years that, that often requires additional investment and can incur additional cost. At the same time, that approach is not mutually exclusive to vigorously managing the cost side of our business to inform asset management, purchasing and innovative cost management. In balancing both sides, better efficiencies will win the day and will remain our primary focus. Going forward, we expect the average daily costs to flatten and trend slightly lower as some of the transitional issues run their course. Only 3 of the 80 rigs we have in the spot market are drilling for dry gas, and only another 3 of the dry-gas-directed rigs under term roll off during the third quarter. Turning for a minute to new builds where our manufacturing efforts continue to lead the industry as we are on track to complete 48 rigs in calendar 2012, outpacing the average of our top 3 competitors in the U.S. by approximately 2x. Since the start of the calendar year, we have previously announced an additional 9 orders to our order book, we continue to deliver rigs at a pace of 4 per month and our schedule going forward to complete 34 fully contracted rigs to customers. This strong backlog will allow us to stay busy throughout the 2012 calendar year. While we are continuing discussions with operators for new builds, those conversations are fewer and we would expect the current rig rotation to have to play out for several months before we gain a better visibility into the customers' demand for 2013 deliveries. We believe that the current new build cycle is far from over and will continue to provide us with attractive opportunities going forward. With that, I'm going to ask John to make his comments. I'm sorry, I'm going back to Juan Pablo for comments and then to John.

Thank you, Hans. As announced earlier today, the company reported $130 million in income from continuing operations for the second quarter of fiscal 2012. Although we continue to experience overall quarterly growth in revenue and rig activity, the higher daily rig expense levels mentioned by Hans contributed to a sequential decline in quarterly income from continuing operations. Nevertheless, it is encouraging to report that we do expect continued growth in revenue and rig activity as we transition to the third fiscal quarter. Our capital expenditures estimate for fiscal 2012 remains at approximately $1.1 billion, and our depreciation estimate for the year remains at $380 million. Our general and administrative expense estimate for the year has increased from $105 million to $110 million, and our interest expense estimates, which is net of capitalized interest, has been reduced from $13 million to approximately $10 million during fiscal 2012. Our debt-to-cap ratio is now under 9% and our liquidity level remains strong. We expect to fully fund this year's CapEx program and other scheduled outflows from existing cash and from cash to be provided by operating activities. Nonetheless, we are working on a new but smaller long-term revolving credit facility to replace the $400 million facility that expired last December. The new facility may be used for issuance of letters of credit, temporary funding or other general corporate purposes during the coming years. Our tax rate for continuing operations for the second fiscal quarter was 36.8% and is expected to remain at approximately that level during the remaining 2 quarters of the fiscal year. I will now turn the call over to John Lindsay, and after John's comments, we will open the call for questions.

Thank you, Juan Pablo, and good morning. The following comments will cover the operational results for our second fiscal quarter of 2012 for our 3 operating segments: U.S. land, offshore and international land, as well as the outlook for the third fiscal quarter of 2012. And I'll begin with our U.S. land segment second fiscal quarter results where revenue days increased 2% to 21,444 days, representing 236 average active rigs in the second quarter. As U.S. land segment took delivery of 12 new build FlexRigs during the quarter. An average of 154 rigs were active under term contracts, an average of 82 rigs were active in the spot market. Average rig revenue per day increased by $764 to $27,625 per day. Average rig revenue per day for rigs working on term contract during the first fiscal quarter was approximately 6% higher than average rig revenue per day for rigs working in the spot market. Most of this difference was driven by the mix of rig types in each category as current pricing is similar for comparable rigs under term and in the spot market. Hans touched upon many factors to consider that can influence variability of expenses from quarter to quarter. In addition, as mentioned during the previous quarter's call as well as in our Investor Conference Presentation filed on March 23, we expected average rig expense to increase by at least $900 per day, given extraordinarily low levels of expense during the first quarter, combined with wage and other increases to be passed on to customers. The remainder of the sequential increase in daily expenses was attributable, one, to higher-than-usual expenses related to high investment rig equipment like top drives and pipe-handling equipment; two, higher-than-expected labor and maintenance expenses associated with rigs that became at least temporarily idle during the ongoing transition in the U.S.; three, higher-than-expected expenses that were passed on to customers; and 4, other expenses that are indirectly associated with rig operations. As a result of the average rigging expense per day increasing by $1,534 sequentially to $13,826, average rig margin per day decreased by $770 to $13,799 per day from the first fiscal quarter. Consequently, U.S. land operating income decreased 7% sequentially to $210 million as compared to the record operating income recorded in the first fiscal quarter. And this quarter is the second highest operating income on record for H&P U.S. land. Today, even with natural gas oversupply and weak prices, we remain positive about the long-term outlook for U.S. lands, as well as the third fiscal quarter. H&P continues to be the most active U.S. land contractor currently with 239 rigs, 239 contracted rigs and 29 idle rigs. Of these 239 rigs, 159 are under term contracts and 80 are in the spot market, including 77 FlexRigs. Not included in the 239 rigs are 2 recently completed new build FlexRig3s and one existing FlexRig3 that are scheduled to transfer out of the U.S. land inventory to international. And I will share more details on that later. In the third fiscal quarter of 2012, we expect revenue days to increase by approximately 2%. Based on current contractual commitments, an average of 160 rigs are under term contracts for the third fiscal quarter of 2012, an average of 157 rigs for the last 2 quarters of fiscal '12 and an average of 129 rigs for fiscal 2013. Excluding costs that are contractually passed on to customers, we expect average rig revenue per day for our rigs that are already on term contracts to increase by approximately $250 in average for the last 2 fiscal quarters of 2012 and by approximately $550 in average for fiscal 2013. Both of these increases are compared to the second fiscal quarter average rig revenue per day for rigs on term contracts. Average rig revenue per day in the third quarter may be flat to up slightly by as much as $200 per day. Third quarter spot market pricing has come under some pressure, but thus far, has been flat compared to the second fiscal quarter. And as we think about forecasting expenses for the third fiscal quarter, we believe a reasonable rough estimate of expenses should be in a range of $13,500 to $13,800 per day. Our FlexRig new build program continues to lead the industry in delivering advanced technology AC drive rigs on time and on budget. Including the 6 new builds announced on March 23, 34 rigs remain under construction and are currently being completed at the rate of approximately 4 FlexRigs per month. Since 2006, H&P has built a total of 209 AC drive new build FlexRig3s, Flex 4s and FlexRig5s, all sponsored with a firm term contract. Now a review of our offshore segment second fiscal quarter results as 2 rigs in the Gulf of Mexico were in transition between projects and our rig in Trinidad completed its contract toward the end of the second fiscal quarter and has been shipped back to the U.S. Primarily as a result of these factors, our offshore operating income decreased approximately $2.4 million to $9.8 million. Revenue days decreased by 10% to 627 days and average rig margin per day decreased by $1,610 to $20,561. Outlook for offshore as of today, the company's offshore segment has 6 rigs active and 3 rigs stacked, 2 of which are contracted. Of the stacked rigs, one of the stacked rigs is expected to go back to work in May and the second is expected to go back to work in the September quarter. In third fiscal quarter of 2012, we expect offshore revenue days to be flat to down 5% and margins to be down 10% to 15%, as one-way rig transitions between projects and one rig begins a new project. The international land segment results from the first fiscal quarter to the second fiscal quarter decreased by approximately $9 million, resulting in a $1 million loss for the quarter. The primary factors driving the decrease were as follows: regular and expected expenses related to mobilizing 3 rigs between countries, all 3 of those rigs now have contract commitments; the absence of a $1.6 million retroactive day rate adjustment in Argentina that was a positive one-off that took place during the first fiscal quarter; a $1 million currency exchange loss and miscellaneous expenses and just other expense items in general during the quarter. Revenue days increased 2% to 1,761 days. Average rig margin per day decreased $4,131 to $4,884 per day. The outlook for international as of April 26, the international land segment has 20 rigs working and 2 additional rigs contracted, one of which is still in transit from Argentina to Colombia. 6 rigs were active and were contracted in Colombia, 5 in Ecuador, 5 in Argentina, 4 in Bahrain and 2 in Tunisia. Of the 4 stacked rigs, 3 are located in Argentina and 1 is located in Colombia. As discussed earlier, 2 recently completed new build FlexRigs3s originally contracted for the U.S. land segment will instead be sent to the Middle East at the customer's request. The first of these rigs is readying for transport and should contribute to the fourth fiscal quarter. The second rig will move in approximately 30 days and should contribute in the first fiscal quarter of 2013. The existing FlexRig3 sourced from the U.S. land segment has signed a letter of intent to work in the Neuquen Basin shale play in Argentina and will be working for a major oil company. The rig should contribute toward the end of the fourth fiscal quarter of 2012. The total number of rigs for international land segment will increase to 29 rigs once the transfers are complete. Of the 29 total rigs, 16 will be FlexRigs. In the third fiscal quarter, we expect international land revenue days to increase by approximately 5% and margins to increase by approximately 10% to 20%. As we move beyond the disruptive effect of starting up the new rig contracts, we are optimistic that the margins and days for the international land segment will continue to increase beyond what we expect in the third fiscal quarter. We believe these most recent international opportunities reflect an improving market for FlexRigs in South America and the Middle East. In each of these regions over the past 2 years, FlexRigs have cut well cycle times by half and are delivering well counts in excess of twice of the competitor conventional rig previously was able to provide. In closing, we continue to witness the ongoing shift to unconventional oil and liquid-rich plays that require drilling of more complex, horizontal directional wells. And we believe that trend is advantageous to H&P. This drilling complexity factor presents operational challenges for many old, conventional rigs and lower-end technology product offerings. These market trends, along with H&P safety, people and performance advantages, provide us with confidence that more opportunities for new FlexRigs will continue. And now I'll turn the call back to Juan Pablo.

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

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

I wanted to ask -- Hans, I think initially in your comments, one of these cost factors is you mentioned more demanded of the rig from the operator. And in that context, I did hear you mention something about top drive investments being higher. So what else is in this category that you call more capability demanded from the rig, which increases daily operating expense?

Robin, I think part of the point there is as we improve our footage per rig and we see the cycle times going faster, you can just imagine you're on an M&S basis, you're replacing more things, that rig is producing more hole every year. So it's just kind of that general notion that as you work faster and the rig produces more, you're going to drive some more costs. But top drives are an example of that, and John may want to comment. But top drives, on a repair basis, you capitalize some of that at first but then you expanse some. And so again, that's an example of an item that's going to drive higher expenses.

Robin, I might add that as laterals get longer, torque requirements are higher. So that puts the top drives obviously in a higher service capability than what historically we've seen previous to the last, say, I don't know, 24 to 36 months. We're also pushing mud pumps harder, the operating pressures are getting higher. That obviously has an impact on expendable cost. You've got your pipe-handling equipment that is cycling the tubulars in and out of the hole at a much faster pace than that we've seen before. I mean, you can just imagine that we're up 10% 10 -- from calendar '10 to calendar '11, another over 10% already in 2012. So it's just a -- this is a much-increasing cycle time. It's great for our customers. It's great for us. But at times, it hits us on the quarterly variation.

Yes, okay. Those examples were exactly what I was looking for. Understood. On the contracting side, are the customers looking at possibly more availability of FlexRigs on the spot market or that may become available on the spot market and prefer that hiring rigs that way rather than committing to term contracts? Or are they kind of stalling to see if more high-capability rigs become available without having to make long-term commitments?

Yes, I think that's happening, Robin. We talked in our last call and this transition from the dry gas to the oil and liquids-rich plays has been going on since the fall of '08, and it's been somewhat orderly. I think with coming out of the winter, the psychological impact of gas prices falling below $2, I think it has focused the operators not only on accelerating that rotation, but then also stepping back, seeing how some of this plays out, seeing what the rotation of rigs will provide them opportunities for, meaning in terms of will they be able to secure Tier 1 rigs. All of that has increased recently. And I think they're playing a wait-and-see game. In our opinion, that takes a matter of time measured in months to work itself out. But it does impact both to your point about are they willing to just immediately rotate into term. It impacts that thinking. And I also think it impacts for a short amount of time their decision on new builds. In a way, the rotation and the uncertainty of this market becomes a competitor, if you will, for additional new build orders. We also think that is a short-term phenomena.

Okay. Just one final clarification on -- you haven't seen anything or you didn't mention anything, as you saw in 2009 where you had customers seeking early terminations of term contracts or paying for rigs to be idle according to the terms of the contract.

I'll say, no, we haven't in terms of comparing it to 2009, where hopefully that was a once-in-a-lifetime event. And that's not happening today. John, do you want to add anything to that?

Yes. I would agree. It's nothing like the '09 cycle. We have had a couple of rigs that have gotten relieved in dry gas basins that have had 30 to 90 days left on their term. But again, those are not big deals.

We'll go next to the side of Joe Hill from Tudor, Pickering, Holt. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Hans, just getting back to some of the points you were making earlier about faster cycle times, higher costs, customer preferences, can you give us a little more detail on strategically how you can recapture that value add from the faster cycle time? It seems like obviously, the market isn't terribly receptive to that sort of thing right now. But if you are adding value with that, I would think you would be able to price accordingly and at least maintain margin.

I think that's exactly right long term. I think, Joe, we're in one of those periods where the softness in the cycle is kind of feeling its way out. We're confident that because of the amount of opportunities from the oil and liquids-rich plays and the amount of drilling inventory that this is a temporary and will end up being a shorter kind of lull in the cycle. But you just think about our approach and why we have a confidence that the AC drive rigs are going to stay active and in high demand. That's based on the efficiencies and the reduced cycle times we provide. And so when we have a customer that says, "Gosh, I'm going to slow down or I'm going to turn a rig loose and we're contracting, keeping that rig active and contracting it with a new customer. We're going to keep the crews intact, we're going to look for opportunities. Hey, let's -- we've got a few days of idle time. If this rig needs to be spruced up some and have some money to spent on it, we're going to do that. And it's, again, part of a strategy of having a premium offerings and premium performance. And I think that in the long run, back to your question, gets rewarded as you've seen with premium average margins but we may be in a time right now where we've got pressure on pricing and then pressure on cost. But I think we'll manage our way through that. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just thinking about the cost bump quarter-on-quarter, can we parse that out? I think it was $1,500 or thereabouts into what was pass-through. I think you guys had talked about $500 in labor pass-through and then what is rotational costs and then what are just inflationary costs?.

Joe, this is John. The $13,200 is kind of our original feeling on where we would be. That was up $900 from the previous quarter. Again, the previous quarter, as you know, was very low. The additional $600 was a combination of things, kind of like I laid out. There's a portion of that, that is associated with top drives and just higher capital cost equipment, pipe-handling equipment, things like that, that were substantially higher in this quarter than usual. The transitional costs that Hans talked about, that was a big portion. We had about 11 -- 11, 12 rigs change hands in the quarter, meaning from one customer to another. About 70% of those or more transitioned from a basin to another basin. So there's -- again, the operator is paying for the mobilization cost but we have those soft costs associated with it that Hans spoke to. You compare that to previous quarters, we had, again, kind of that churn, if you will, from customer to customer, similar type numbers but a very small percentage of those went basin to basin, so you have a much less expenses and much less time kind of waiting between locations, if you know what I mean. So that drove that. There's a certain aspect to just other higher costs that are passed through to the customer. And then finally, just the other side of it that aren't necessarily directed right at what's going on at the rig, whether it may be taxes or whether it may be overhead type things that just hit in this quarter that were higher in this quarter compared to the last quarter. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then last question for me. What's it cost you to move a rig to Latin America or the Middle East?

I'm thinking ballpark. A range -- just the mobilization cost is it's probably $1 million to $2 million. Again, there's a lot of variation there. Those are typically reimbursable costs. Those are costs that the operator foots the bill on that. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. Is that amortized or is that taken lump sum?

It depends on the project. Typically, it is amortized.

We'll go next to the side of Michael LaMotte with Guggenheim.

If I can ask about the 3 contracted rigs that are rolling over in the third quarter, and maybe you can put this within the context of what you've seen in the last couple of quarters with rigs roll off. What percentage can we expect to sort of stay with the existing original contract or writer? What's sort of the retention rate that you all are experiencing? And if you look at the last couple of quarters, Hans, you've mentioned cost pressures and price pressures a couple of times without getting too specific. I'm wondering if you can quantify that whether the market is really sort of trending flat on your rollovers or whether we can really see rigs tick down on any of these rigs as they roll off.

Good. Well, we might provide some clarification. The 3 rigs under term that roll off are rigs that are gas-directed today. So we're just projecting that as those roll off and come into the spot market that we will market those into a region that is more oil-directed. So I think I heard your question being would we anticipate that those go back under some kind of term contract? I would think today in this market, they probably would not, particularly though to the customer and what the customers' plans are and how they want to position their own rig rosters. And so it wouldn't be unusual for it to roll into a term that might be shorter than the 3-year term that it rolled off of but still under some kind of term coverage. We mentioned just the term coverage going into the second part of the year is still being robust at 157 rigs that will remain under term contract through the rest of our fiscal year. So I hope I'm being responsive to what your question is.

You are, Hans. I think -- I was getting at the retention side of it, but I think what you're saying is when they're released, they're released, and they're really out for tender to the marketplace as opposed to likely to be re-contracted with original operators.

Yes. Well, I don't want to overstate that because we would expect to have a chance for that original operator to keep that rig and keep it working. I mentioned the 3 again because to me, the point is that's a pretty small exposure to dry- gas-directed rigs. And so we have 3 in the spot market. We have 3 that will roll over in term. So I was trying to give you a sense of, well, is this rotation going to look as tough in the next couple of quarters as it might have impacted us this quarter and the answer is, no, it won't. So whether those 3 rigs stay with our customers, I don't want to imply that they absolutely will not. They may.

I might add a little bit of detail to that, Michael. In those particular cases, I think 2 of those 3 will roll to different customers, and the pricing will be flat to slightly up on those particular contracts. The other rig, I think, will most likely stay with other customer. But part of what's going on in the background is -- in these -- in the 2 cases where the rigs are changing hands, they're -- those rigs are actually going to work for a customer that has a competitor rig rolling off of term, and this rig is going to go in and fulfill that particular slot. And then I think in one case, it's going in on a spot well-to-well contract, and the other case, I think we're picking up maybe a one-year term. But as Hans said, there's really all kinds of variations, but what we're seeing is quite a bit of interest in FlexRigs, and particularly in the Eagle Ford and Permian and somewhat in the Bakken, but particularly, in the Eagle Ford and Permian.

That's helpful. I think where I was going with the follow-up was if there is concern about day-rate degradation in the market more broadly, what's the sort of staying power or stickiness of the FlexRig based on performance? And I know everybody throws that term out, bifurcation, but can the markets really -- can the performance differentiate in a looser market? And it sounds like that's the case if we use the example of those 3.

Well, I think that's right. I think that there are pricing pressures out there. There's some collateral bleed-over from the price reductions you're seeing in pressure pumping where that also kind of pulls in the drilling rig in terms of the customer. I'd love to see prices go down. But at the same time, we're hoping to see the stickiness on pricing based exactly on what you're talking about, the performance and looking back over just the most recent soft cycle where the pricing for the highest performing rigs. So if you will, the bifurcation did occur where those rigs remain at the higher pricing level.

And last one for me, a little bit more longer term, if I can. As I've run through the model and what your cash generation looks like with the base of FlexRigs that you have in the fleet, the CapEx requirements even at a decent pace of new building are much smaller relative to your overall cash flow. And I'm wondering if you've given some thought to the issue of cash return, what that might look like over the next 2 or 3 years. And maybe within the context of that question, if you could address the equity holdings in other companies that you have.

Okay, good. In terms of the crossover point where we begin to generate free cash, I think we'll go look for what opportunities do we have to achieve high rates of return on capital. And if we don't have the building opportunities, you won't see us stray very far in terms of acquisitions or investing in other things. So it gets back to a pretty straightforward approach to how will we return that free cash to shareholders. And there are not that many different ways to do that, it's either through share repurchase or higher dividend streams. So those are things that we'll look at. What we're hoping to see is this replacement cycle providing opportunities where we can continue to build and provide the kind of attractive returns that we've been able to historically secure for that. So it's a good question. And then your question about the equity, in primarily at the Schlumberger and Atwood. We that as a source of funds. So we would like to see those funds rotated into FlexRigs.

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

Nabors announced they had 9 term contracts with a major operator for 3 years, expect it to generate $280 million to $300 million and another $25 million if they use the Canrig Technology. This would work out to day rates of about $28,400 to $33,000. Is that more or less the range of day rates you're getting on new motors?

Well, Mike, we saw that announcement too, and we're still kind of sorting out, some of it was rigs that they had already built on spec. And so we're trying to sort that out. And you're backing into a day rate range. I think some of our newer day rates are in the high 20s and slightly higher than that. So, John, unless you have something else in terms of what you know about competitive...

Yes. Mike, the 28 to 33, I think that appears to me at least to be on the high side of what would be possible. But, again, I don't have any other details besides that.

I guess, this could be for the Bakken where the drilling costs are higher because of the weather?

That would be more reasonable. I wouldn't expect to have that kind of a revenue stream in somewhere outside of the Bakken. Because Bakken expenses are quite high and the investment is quite high.

[Operator Instructions] We'll take our next question from Mark Close with Oppenheimer & Close. Mark Close - Oppenheimer & Close, Inc.: I wonder -- can you -- the $13,200 expense level, is that -- do you think that's attainable by, say, calendar Q4 of this year to get back down to that from a trend standpoint? And the other question is, regarding Argentina, obviously there's a rather unsettled situation there, and there's been -- I think, those 3 rigs that are stacked have been idle for quite some time. Is there a thought to moving them out of Argentina? Are they being marketed elsewhere, or is there a likelihood that they'll be put back to work?

Mark, this is John. I'll start with Argentina. There are 3 rigs stacked there. I think there's a likelihood that at least one of those rigs will go back to work fairly soon. It's not going to impact third quarter, maybe not even the fourth. But I think it will go to work. And I think the other 2 rigs will have an outlook for activity. They're bigger rigs, so they're not rigs that would be directed towards the shale play in the Neuquen area. I think they do have opportunity to work in the Neuquen area on deeper type of activity. So I think the rigs, it make sense for them to be there right now as evidenced by we did move a 30,000-horsepower rig out of Argentina. It's going into Colombia, and it does have a contract. So if we are successful in getting a contract outside of Argentina, then, yes, we'll move the rig out of there. I mean, we're overall pretty excited about Argentina and the opportunity there and excited to have a FlexRig going in down there. I think it will start off as a nice trend for us. On the cost, again, we're all disappointed in the high expense that we had for the quarter. But it isn't unusual to have some pretty high variation just on a quarter-to-quarter base. And I think for us to talk about $13,200 right now is a little unreasonable. Again, we're kind of thinking this $13,500 to $13,800 range and that's where we're hoping to get. I haven't really started thinking about fourth quarter yet. It's always possible, but again, we're seeing, as Hans mentioned, we're seeing a lot of demand put on the rigs, and there's still this transitioning of rigs from basin to basin, even simple transition, they seem very simple, we're even seeing the rigs transition out of Eagle Ford into the Permian. I wouldn't be surprised to see some rigs in Oklahoma transition into the Permian. So I think this transitional period, I think, definitely happens through the third quarter and it may even continue into the fourth quarter. It's just hard to say right now.

We'll go now to the side of Josh Lingsch from Simmons & Company. Josh C. Lingsch - Simmons & Company International, Research Division: Going back to the previous question about the gas rigs going off term and the 3 rigs in some market. How many are those are expected to return in gas markets in and the next 6 months to a year.

I'm sorry. What was the question? Josh C. Lingsch - Simmons & Company International, Research Division: Going back to the gas rigs that are rolling off contract, the gas rigs you still have in the spot market. How many of those are expected to remain in gas markets? And the reason I ask is if you're moving those into oil basins, is the customer still paying for that move or is that something that you're proactively moving to an oil market and pay the rig costs, pay the cost of rig move yourself?

I suspect in the case of the 3 that were mentioned earlier, those are going to go to work in oil and liquids-rich markets. And I would say in most cases, the rigs will rotate out of gas into the oil and liquids-rich, but not in every case. But I think in most cases, they will. The mobilization cost has been on the operator, the operator has paid that. And so that's kind our expectation going forward is that they'll continue to do that.

And we have no further questions at this time.

Thank you, Priscilla, and thank you, everyone for joining us. Have a good day.