Nabors Industries Ltd (NBR) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Nabors Industries third-quarter 2011 earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions) This conference is being recorded today, Wednesday, October 26, 2011.

I would now like to turn the conference over to Mr. Dennis Smith, Director of Corporate Development. Please go ahead, sir.

Thank you, Alicia, and good morning, everyone. And thank you for joining us this morning. In addition to myself, Gene is here, and we'll give 20, 30 minutes of prepared remarks, by which we will follow with a question-and-answer session, and try and wrap up in 1 hour or so. Tony Petrello, our President and Chief Operating Officer, is also here, as is Laura Doerre, our General Counsel; Clark Wood, our Principal Accounting Officer; and I think every one of our unit heads is here at the table with us as well this morning.

Just want to remind everybody that we are going to be discussing not only quarter results, but how we see our best estimates on how we see the near term and the longer term going forward, and of course, those constitute forward-looking statements as defined by the SEC, and are subject to a lot of risk and uncertainties going forward. I would encourage you to refer to our filings for identification of those factors.

And with that, I will turn it over to Gene to go ahead and get started.

Thanks. Again, welcome everybody to the conference call for the third quarter of 2011. I want to thank everybody for participating again. Thank you again for participating this morning. As usual, we have posted to the Nabors website a series of slides that contain details about the performance of the various segments of the Company, and you may care to peruse that as you listen to the call.

Nabors had a very solid third quarter, driven primarily by very good results in almost every one of our business units. Land drilling in US and Canada, well-servicing operations, pressure pumping, almost everything, can rig, everything was performing on all 12 cylinders. These results more than offset the seasonal decline in Alaska, and less than stellar performance in our international operations. The largest sequential increase in operating income came from the seasonal rebound in our Canadian operations, which improved by approximately $24 million. This was particularly noteworthy since the quarter got off to a slow start due to weather-related issues. This should serve as a good indicator of the performance we expect as we enter the winter drilling season.

Results in pressure pumping operations were up by more than $20 million-odd in the quarter as weather issues and delays in equipment arrival and also gearing up with manpower to work the equipment before the cash flow actually occurred have more or less been incorporated and are behind us. We also are beginning to realize the impact of the increased capacity we have been deploying since -- ever since this unit was acquired. Our financial position remains strong, and our access to low-cost capital remains good as evidenced by the mid-quarter placement of $700 million in 10-year notes at just a little over 4.6%. The proceeds from this placement were applied to the money we had pulled down on our revolver.

We are decommissioning a number of rigs, which we have deemed to be no longer functional or economically viable for current market operations. All of these I think are a noise, and therefore, I wouldn't consider the economic impact as anything significant; however, we are putting down, retiring 100-odd rigs in the US. Half of these have really not even worked in recent memory, and only 7 of these were SCR rigs. In well servicing, we are retiring 84 rigs and 60-odd trucks, some of which were never actively -- very actively marketed recently. Another 13 rigs are being retired in Nabors International, including 1 rig mass supported jack up. The impact of all these is about $100 million of write-downs, which I suggest, again, we ignore. These write-downs were partially offset by about $40 million-plus worth of noncash asset gains that accounting requires from acquisitions.

Before I turn to the units, let me give you my overall thoughts on the big picture as it affects our sector and in particular, our stock. While we recognize there is a risk of slowdown in customer spending, in other words, we cannot control the macro situation. Even in spite of that, I remain very, very comfortable and confident, even in the short term. This confidence stems from the number of term contracts we have in our US land drilling fleet, and term contracts in our pressure pumping operations, and the fact that 75% of our current income stems from oil, which is deeper and less likely to be volatile in the foreseeable future.

Let me turn to the business units. In the USA, reporting operating income of $100 million, up from approximately $99 million in the previous quarter. I guess we are at a point where $100 million is really the new par for a quarter, and that is very good. And we are continually getting requests for built-for-purpose rigs, and we expect we will have a considerable number of new builds over the next 12 months, and the order flow is continual as we speak.

Today, we had, I guess 216 rigs working? And demand, as I suggested earlier, seems to be unabated for built-for-purpose rigs. Margins for the quarter were de facto up about $370 [million] a day, which is good, and is a reflection of good cost control and robust market conditions. Going forward, we expect continued income growth fueled by these new deployments and also by, frankly, an increase in margins, which is continuing.

Some of the rigs that we put out earlier on terms were a little lower than, in retrospect, they needed to be. And as these contracts expire, they are being replaced at higher margin contracts. The stellar performance of our new build rigs continues to impact favorably on our ability to grow this business.

Superior well services results of $65 million in our pressure pumping operations are up approximately $20 million-odd over the prior quarter, and they are approaching the level, frankly, that we had expected after we acquired this unit. The timing, I think in retrospect was pretty good, and business there is pretty good and continuing strong. Although it is pretty clear that we had continued to have one-year payouts on new investment for very long, so there is -- we are trying to make hay while the sun shines and do what we can to convert into multi-year term contracts.

Our third-quarter results were primarily driven by increase in [stage emphasis] on well servicing, and by the deployment of additional spreads. By the end of the quarter, we had 19 crews -- large crews running, which constitute just under 700,000 of fracking hydraulic horsepower. We also have 13 term contracts in hand, which is -- traditionally has been unusual in this business, and frankly, we expect to increase that number. We still have 6 or more spreads to deploy, the impact of which will provide significant sequential improvements during the next 3 quarters, and I think that will mitigate the effect of almost universal increase in supply because of the high margins and short payouts.

Nabors Well Servicing posted a $23 million in operating figure, a significant sequential increase over just under $17 million we posted in the prior quarter. The performance was largely attributable to a significant increase in truck hours, rig hours, and rig rates, essentially everything. Although a substantial portion of the increase was absorbed by wage increases, particularly in Canada, but net-net, bottom line improved. We are beginning to see the impact of incremental capacity in this unit. In the last 9 months, we deployed 1,000 new frac tanks, which we'll continue to deploy, most of which, 90% of which are on term contracts. And we have brought into play 150 truck tanker combinations, which are not on term, but when the frac tanks are on term, these are essentially tied to that term. This brings the frac tank fleet to approximately 3,800 units, with 500 more on order, and with options for additional units, and we are marketing these full speed ahead.

We have added or will soon add 20 400-horsepower rigs in California, 4 already deployed, 6 more will be deployed by year end, and the rest in the first quarter or early next year. The fluid hauling truck fleet now stands at 835 units, new additions are, among other things, bringing the average age down to a little over 4 years. The outlook for this unit is, I would say, excellent. The impact of the new capacity ramp up in the Bakken shale, and today's high level of conventional and unconventional oil drilling should result in essentially continual improvement of results. We are also seeing an increased amount of P&A work, and current volume oil drilling should fuel the mechanical pump market long term, which also augurs well for our business.

Turning to Canada, we are experience an exceptionally strong recovery in Canada after the traditional seasonal weak second quarter, with operating income increasing to almost $22 million for a loss of $2.5 million in the preceding quarter. The outlook continues to be good. Despite July's being -- recount being weak due to weather, the average rig count for the first quarter almost doubled, increasing from 22.5 rig years to 42 rig years. Today's rig count stands at 46 rigs. The continuing increase in this unit's drilling rig count, combined with an increase in work-over rig hours, should fuel strong third and fourth quarter results as we get into the peak winter seasons.

No signs of slowdown in this market. On the contrary, we are processing increase for additional rigs, a significant number of which will be directed to our rapidly developing Guardian field, which is increasingly a year-round play in Canada.

We are also seeing surprisingly robust activities in the British Columbia shales. I guess in terms of -- there has been a project already announced in terms of in situ conversion from gas to oil, as well as potential exports of LNG, et cetera. But in any event, people are moving ahead with drilling and developing, making the reserves available there, which is a pleasant surprise.

Nabors Offshore -- our US operations rebounded from a $1.3 million loss in the second quarter to a modest profit in the first quarter. But essentially, when we start drilling there, we'll do pretty well. We more or less can figure around $40 million if we operate for full year there, and if -- when they permit drilling again. And if it's a half a year, it will be half of that $10 million -- $20 million for the year, et cetera. In other words, $10 million a quarter that we operate there, approximately.

We are also managing a significant deepwater project there, and we'll have a number of progress payments, so we will be showing profit there. And also, we will be developing a project that we will -- that project we'll sell and operate -- ride the operating [revenue]. There's an additional project we are working on which we will own and operate [in the Gulf].

Alaska -- this unit posted modest results, $3 million, down seasonally from $8 million-odd in the prior quarter. We expect fourth quarter will be very similar. Although these results obscure what promises to be fairly robust increase in the first quarter of 2012 as activity picks up during the winter exploration season. Nabors has already received commitments, I'm told, to drill approximately 85% of the season's exploratory and delineation wells, which speaks pretty well to our market position and performance. Long term, this area offers, I think, really significant [augumetric] promise in terms of the lower end of the high this [proves] that are available in super abundance in Alaska.

International results in this unit were $29 million, down from $35.5 million in the prior quarter, and below our previous forecast that results would be flat. This is largely attributable to ongoing delays in Iraq particularly, and the delayed restarting of two jack ups, repairs of which required unexpected amounts of incremental steel.

Other operating segments -- this unit was up significantly, primarily to the growth in Canrig, which continues to do outstanding bottom line delivery work. The outlook for this is particular good. Hand rig, Rocket, [Soft Tour], [SureGrip] combines with very lucrative, or at least attractive third-party equipment sales is driving this unit. Our top drives particularly are being well received in the market. Forward results should be boosted by improving market share by Ryan and peak ramp up for yet another robust Alaskan season.

Oil and gas, we are doing extremely well. We don't report this really on an operating income basis. We develop oil and gas, and whether we produce the oil and gas ourselves is something we look at as we are in different -- whichever provides the highest return, we will go within. Traditionally we have been selling this stuff, so it isn't operating income, but it is essentially recurring, nonrecurring income. Nonrecurring accounting-wise, but from a pragmatic viewpoint, it's continuing and we continue to do well there, I guess we would be 6 or 8 months away from another significant sale there.

While I'm obviously aware that there are macro circumstances that could adversely impact us, particularly commodity prices, which are not easy to predict, global drop in GNP. I think we are less vulnerable now than we have been for a long time. For example, prior to the market slowdown in 2008, annual operating income internationally was $500 million, at an annual rate, and maturing contracts were set for renewal and some didn't renew.

Today, it is essentially the other way around. We are at the low end of things, and the potential changes are very likely to be for the upside, particularly since international is largely oil driven, and the oil market is stronger, it's longer, it's deeper, it's hedgable, et cetera. Actually, in 2008, 85% of the US and Canada drilling was driven by gas. Today, surprisingly, over two-thirds is derived from drilling for oil and oil content.

We also have a surprisingly significant degree of contract coverage protecting our US land income projections, and also surprisingly recently for our pressure pumping operations. I feel pretty good about the factors that are essentially within our control, and my best guess is that the macro circumstances won't interfere with our achieving our own objectives.

That is my comments.

Operator, that wraps up the formal part of our presentation. We are ready to commence the Q&A session, please.

(Operator Instructions) Your first question is from the line of Ole Slorer with Morgan Stanley.

Thank you very much. Gene, I wonder whether you could just share some, call it some leading edge day rates with the stock market, or whether it is for term charter. How have this been developing as of late compared to what you have in your portfolio, for example, or other market trends in general?

Okay, I will turn it to Joe for that.

Yes, Ole, the leading edge rates are in excess of 28, they are in our northern area. And in the southern area it is about 24 plus some change. So, we continue to see on the new builds some improvement in day rates on the new builds. And then also in the northern areas, some of our existing conventional rigs we also have some very attractive rates. Again, this would be pretty much in the Bakken area, so it is -- I think it is still pretty strong.

Joe, were these spot rates or term charter rates, or is there no big difference in the two?

In the northern area, there is -- we have a lot of those rigs that are contracted. On the new builds and on the conventional, there is not a large spread, maybe 5%, 10% spread between the two in the northern area. In the southern area, there, again, not a large spread between the new AC and a lot of the conventional -- not conventional, but some of the -- as Gene mentioned, some of our term contracts rolling over on the AC rigs, and we are pushing those rates up to those areas also.

It sounds as if the new business that you are looking at on average is still at a higher level than the average of your backlog, would that be fair?

Yes.

And you've decided, maybe overdue, to scrap a number of the older rigs and continue to embark on the fleet renewal project. Could you talk a little bit about why now, and is there a technology change going on in the US markets?

Yes, I think the emphasis was, we would. I think we have approximately 25 mechanical rigs in the field. As Gene mentioned, of that number, only 7 were SCRs, so, again, there is not a lot of upside for those specific rigs. So anyway, the decision was made to retire that equipment and focus on existing upgrades and technology. I would point out that with our canrig AC top drives, we've got approximately 160 to 165 AC top drives deployed in the field, so not only do you have the AC rig going, but you also have the AC top drive performance. We deliver a lot of product with that.

Okay, I see. And on the international side, Siggi, I wonder if you could just give us a little bit of a road map to the 130 in a specific geographic region that will take you there? That is above what you were running at peak in 2008, for example.

Yes, basically the majority of rigs that we start up, there's a big -- 9 rigs going up (inaudible). We have additional rigs going up in Nigeria, we are starting rigs -- additional rigs in Kenya. So, right now there is (inaudible) rigs in the works, so as you can imagine, this is fairly busy right now.

And Siggi, how dependent is this on the, let's say, normalization of North Africa or Libya, Algeria or a stabilization of conditions in Iraq? If that was to push out, how negatively affected would you be?

They are not included in any of this. They would come as a bonus; if Libya starts up again, it would be a bonus.

Okay, finally a question on the pressure pumping margins. You're still a tad below that of your peers, although you are showing some good improvement. Is there room to improve this further as you become more efficient in your equipment or in an environment where cost pressures, logistics pressures with sand, et cetera, are neutralizing some of this potential to further improve?

I think basically, those were due to stuff that, in theory, should be capitalized. You are adding people, you are getting equipment before you can fully deploy. In other words, the expenditure of personnel and equipment is before the actual cash flow, and you're taking -- as you expand, you're taking that [hicky], even though in reality, it's just capital for the cash flow that is going to ensue later.

Okay, so we should see continued improvement?

Yes, unless we continue to expand capacity at a pretty large rate.

I think also, the long-term agreements of the new business model for Superior, and the beauty of these is, as you form an alliance with your customer, that you are going to gain a lot more efficiencies, not only in increasing revenues with more stage counts, but just better utilization of people and resources. And also, it will take a while for our infrastructure to catch up, as far as material handling, and we can see some efficiencies there that we will continue to gain over the timeframe. But, as you can tell, we are pretty excited about that, and we do expect our efficiencies and our margins to improve.

Sounds good. So, Gene, it sounds like you can get close to $0.50 a quarter then without having to rely on the elusive international recovery.

(laughter) Yes.

Okay, thank you very much.

International is based on oil, and that is very strong. So, sooner or later, if we live long enough. Anyway -- who do we have next?

The next question is from the line of Marshall Adkins with Raymond James.

Good morning, guys. That was good color on the pressure pumping average margins. It looks like pricing and margin trends still up. But on the land rigs, leading edge is up, but help me understand the average -- for the full fleet average, should we expect that to trend up? It looked like it was kind of -- if you pull out the one-time things, that was a little flat, and work-over seemed to see a nice jump in pricing. A lot of that may be pass-through stuff. What is the outlook there for pricing, and margins as well?

Drilling first.

Average more so than leading edge.

Yes, again, we -- I think, Marshall, when you pulled out the lump sum, the actual margin was about $350 on a quarter-to-quarter basis.

The improvement.

Yes. So, the -- we expect for the -- obviously as rig demand occurs and continues, we have rollovers. As Gene mentioned, we have good strong protection with our term contracts. However, with that, they have been focused, and we space these out as far as renewals. And we are looking in the next year, somewhere in the neighborhood of the next 12 months, of about 95 of these coming into expiration point some time in that period. So, there is going to be opportunities there to improve the margins. We expect to see continued improvement on the margin line for the rigs on a go-forward basis, yes, to answer your question.

Terrific, very helpful. And work overs, kind of been hit or miss. What do you see there?

Well, basically, we had a fairly good increase quarter over quarter, roughly about 10% to 12% on our rig rates, on daylight rates, and some increases on our 24-hour rigs. As Gene pointed out earlier in his conversations, some of that obviously was taken out by additional cost where we had to give wage increases, particularly in California. So, some of that falls through to the bottom line, obviously, with some of that was taken up by cost increases. But for the next foreseeable future, especially on the fluid side, we continue to see improvement there. So, we expect at least to do something comparable in the next quarter.

Terrific. Last question for me -- Gene, you did not talk a lot about E&P. Could you give us an update on what is going on there -- sales, acquisitions, et cetera?

Well, it's going to be mostly sales. My guess is that 6 or 8 months from now we will have another batch of sales where we will be selling stuff in Colombia. The project there is -- what we do is we develop it on sort of a recurring/nonrecurring basis, and we don't worry about operating income or capital gains or whatever. And the bulk of the margins have been in recurring and nonrecurring events. In other words, we sell the stuff, and my guess is the next lot will be 6 to 9 months from now. That operation is continuing good. The returns there, I have not really calculated them, but they are extraordinarily good.

Great, guys. Thank you, all.

Thank you. The next question is from the line of Robin Shoemaker with Citigroup.

Thank you. Gene, I just wanted to -- your comment about -- on pressure pumping, making hay while the sun shines, I think is a good one. But in terms of your current exposure to where we see the declining activity, the dry gas basins, could you describe that, and what you are -- are you moving some spreads to -- from the dry gas basins currently?

Go ahead.

Yes, we've -- at Superior we were heavily focused on natural gas before, and the last several quarters we have shifted quite a few resources to the oily areas, which would be Rockies, Southwest, Eagle Ford, Permian, and then even some of the liquid areas in the Northeast. And if you look at our percentage of horsepower, we are probably close to 70%, 75% in the liquid areas at this point. And that is where we've had a lot of the success, again, aligning with our customer on these long-term agreements. So, I think our outlook is -- oil looks strong, natural gas looks like it's going to be under pressure for a little while, so we will continue to focus on the liquid areas.

Right, so, no difficulties moving out from one to the other in terms -- in some cases, it is customer directed, it sounds like.

That's correct, yes.

And if I may ask, there is a lot of discussion, and apparently some confusion from time to time about the spot pricing for pressure pumping fleets as opposed to term. And you've got some of both. Of course, it varies by basin, I understand. But would you describe what the margin difference is typically in a given basin between spot and term pricing for pressure pumping services?

As you said, it can vary by basin. I would say, again, you look at some of the softer areas, and you can see a 5%, 10% difference in discount, which, again, coming off the level where it was. And it is not where it was in '09, but it is definitely a lot better in some of the more aggressive areas. So, we look at it as pretty easy to move resources, and we would rather shift it to some of the more active areas to take advantage of that.

Okay, so the term is 5% to 10% below spot in a typical basin?

No, that's not quite what I was saying. I was saying that basically good basin versus some of the softer basins, you might see a 5%, 10% difference in discount. Most of our terms are in the aggressive basins, which would have, again, be on the upper end of that pricing level at this point.

Okay, understood. And if -- one further question on the international. In terms of new contract pricing on land rigs fit for purpose, is this -- how would you describe the level of competitiveness on bidding in international land contracts? And of course, that again varies by region, but are you seeing pricing improvement on contract rollovers in international land?

We just see slowing. Utilization, as you know, is going up in the international market, so we just now see better rates when we leased a new contract, except on the OSHA side, of course. On the OSHA, we don't see anything yet happening for us.

Yes, okay. All right, thank you.

Thank you. The next question is from the line of Scott Gruber with [Alliance] Bernstein.

Yes, thanks. I want to start with the outlook for Saudi, and just to clarify, you provided good color on the jack ups, but are you also seeing a material push to the right for the land rig reactivations?

I can only tell you on the last awards we have seen, on the gas rigs that we have seen higher rates than we have ever seen in the past in Saudi before. So, the rates have definitely gone up, but also have some of our costs, of course. But proportionally, the rates are higher than we have ever seen before.

Right, but just on the reactivations, timing of putting the rigs to work. I believe on your last call you were forecasting getting up to over 30 rigs active in Saudi by 2Q of next year, is that still achievable?

Yes, we are awaiting the final stages to get the last 9 rigs back to work, and by -- basically, they're starting up by the end of the year, beginning of next quarter, so second quarter is clean while working.

Some of that, Scott, some of the modifications we're doing on those land rigs, the customer started the rig up and then asked that we defer modifying it until a subsequent shutdown. So, that is kind of what has moved a little bit of this to the right.

(Multiple Speakers) What we typically do with (inaudible), we get started because they want us to get started, but then we take a break during a rig move, take a planned shutdown, we call it, and some of those occur in the first quarter as well. That's about 5 or 6 rigs that are going to do that. But --.

But that is part of the recent rescheduling of the timeline.

Yes, but Q1 -- [second] Saudi space here is at maximum utilization.

Okay, great. And then just on Saudi in general, is there any sense -- it doesn't sound like it based upon your previous response, but is there any sense that they are starting to drag their feet a bit on oil-directed investment, given the macro uncertainty?

I don't think so. I think that they have a very balanced -- my impression is that they have a balanced portfolio between gas exploration and oil. We have rigs working in all the areas, so I don't see either area being preferred.

Okay. And then a final question on pumping, beyond the 6 additional spreads due out early next year, how are you thinking about investment in pumping next year? Prices remain very healthy, obviously well above the level you need to justify the investment from a term perspective, but assuming we do see some slight moderation in pricing next year, do you continue to add at the same pace to try to keep or take some share? Obviously you are moving into Canada. Or do you moderate the pace of investment some if prices moderate some? If you could provide some color on how you're thinking about it strategically?

Go ahead.

Well, we are obviously very encouraged with the long-term contract success that we have had so far.

At least term.

Term, yes, that. And we feel like, again, this is something that we can continue to add to and improve on. With that, we expect to continue to keep adding horsepower. We haven't firmed up our budget for 2012 at this point, but we can still see opportunities out there where we continue to add to the fleet. Not only here, but also in Canada.

And the returns of capital are still higher than are going to persist (inaudible). Get your money back in 1 year, 1.5 years, and that means it is not going to last forever. That means you've got to do what you can while you can, and what that means is emphasize like crazy multi-year deals where you have at least 2 years plus an incumbent's position on the period beyond that, which we're doing.

Great, thanks.

Thank you. The next question is from the line of Jeff Tillery with Tudor, Pickering & Holt.

Hi, good morning. I was hoping you could provide a little color on Canada, just where you stand from a capacity utilization standpoint? Is Q4, and Q1 essentially, going to be fully -- everything you can work out working, just level of customer interest in new builds out there?

Canada is surprisingly strong. We are also getting essentially built-for-purpose or new build requirements, and there are more areas of moving into a 360-day year compared to what is traditional up there. So, it's strong, I would say surprisingly strong, and I think our fleet is bigger than average, which is what the market is now requiring, so I think we are doing well there. And I have the distinct impression that we are doing better than our market position in expansion. So, up there, it all looks pretty good.

Are the returns on new builds up there comparable to what you're getting in the US?

I think so. I think the problem had been less than a 365-day year been traditional up there, and that is moving in the right direction.

Okay, and then with the US assets written off and being scrapped, can you give us color just on how many idle rigs you have in the US right now?

Joe?

It is, approximately -- we're --.

Why don't you break down to --?

We're around 49 rigs.

Some of the rigs you are scrapping were not even marketed, right?

That's correct.

How many of those? About half?

Yes.

In other words, of the total amount, half were essentially taken out of service a while ago, de facto.

So, that is the answer, is what we currently have stacked at this point in time.

Okay, great. And then last question -- any color on CapEx for next year? Should we expect it to be flat, up or down versus 2011?

I haven't looked at it.

Down compared to 2011 --. It is down, Jeff.

Well, it starts down, but it never stays. I mean, if there are opportunities, we have plenty of money to take advantage of them.

All right, thank you, guys.

Thank you. The next question is from the line of John Daniel with Simmons & Company.

Hi, guys, just two quick ones for me. Gene, you guys had mentioned expansion into Canada in the past with pressure pumping. Does that 855,000 horsepower estimate incorporate the equipment that would go to Canada?

It does not at this point.

How much would you look to take to Canada?

The first two spreads are going to be approximately 40,000 horsepower that start up towards the end of this year, end of fourth quarter, early first quarter.

Is that 40,000 per spread or are those two 20,000 --?

It is 20,000 per spread.

20,000 per spread, okay.

Yes.

All right, great. And then, on the well servicing, I don't know if you said this, I apologize if you did, but what is the marketed well service rig count today? And I think there was a statement made by Steve that, with respect to pricing, that something comparable in the next quarter? I want to make sure that he was referring to pricing up another 8% to 10% in Q4 versus Q3, if I heard that correctly.

That was Larry, but --.

I apologize.

Basically the marketed, the number of units we marketed, somewhere around 470 or 480, and we're -- as Gene pointed out, we have written off a number of those rigs, but those rigs, again, were rigs that were really -- had never seen daylight for some period of time, so --.

Yes.

And my comment on the quarter-to-quarter was -- we expect to see a comparable revenue quarter as Q3.

I see, okay. Got it. Thank you for the clarification. That is all.

Thank you. The next question is from the line of Geoff Kieburtz with Weeden & Company.

Thanks. Are we done with the decommissioning?

As far as retirement of rigs? Yes.

Sorry, we are finished with the decommissioning?

For now. Over time, there is likely to be more as you go. There is still some -- but for right now.

All right, but kind of for the foreseeable, like next year or so, or is this kind of a -- are we in the midst of a culling of the fleet?

No, that is right.

Okay. And on the pressure pumping, do you have basins where you have frack equipment both on spot and on term contract?

We do at this point, and again, some of the more active basins we have a combination of both.

Okay. That is what I meant, single basin where we could make some sort of calibration of the difference in pricing that is associated with a term contract versus a spot contract, normalizing for the basin variations.

Yes, we have a combination of both in some of the basins. Again, our focus is to shift more to long-term agreements, but at this point we have a combination of spot and contract in some of those basins.

And when you look at that, what is kind of the ballpark difference in pricing per stage?

At this point, it is, again, the more active areas, and we are probably not seeing much of a shift at this point. Again, we expect that we could see a little more spread going into the future, but at this point, in the hot spots it is pretty consistent.

Okay, so no real pricing difference term versus spot at this juncture?

On the crews that we are working, that is correct.

And what kind of difference do you see in the utilization between a spot crew and a term crew?

You probably see maybe 25% less on a spot crew.

Okay.

And you just get those gap weeks where you finish up one project, plan on moving on the next project, and there may be some timing issues as far as going on the agreements. There is definitely -- you kind of get into a pattern where you are more efficient, and can really plan ahead, everything is kind of laid out. Usually the spot is a little more multi-customer, and you will have a few gaps in there. It is probably 25% less.

And roughly, what percentage of the currently deployed capacity is on a 24/7 schedule?

It is about half the crews at this point. Part of the crews in the future we expect to move up to 24 hour. Some of the basins will be -- they're probably more vertical wells, more, again, daylight work. But we do see at this point about half moving up a little bit in the future.

Great, thanks very much.

Operator, I think we are running up against our time constraints. We will entertain one more question, please.

Yes, the last question is from the line of Kevin Simpson, Miller Tabak.

Thanks for fitting me in. I guess the question, Gene, is for you, Gene, is on kind of cash generation or use going forward. The Company continues to be a net consumer of cash, and it speaks to the budget question for next year. At this point, should investors just not see that as a priority of management to begin to generate cash and bring the net debt down? Or in the hierarchy of what looks like cash flow is going to be pretty strong next year, and well protected, are you going to -- do you see putting a higher bar for some of the capital projects, especially in overseas and maybe looking to generate more cash?

Frankly, I think -- I've always considered the project, good projects to be the scarce resource. In my career with Nabors, my whole career, it has never been a problem to get money for a good project. The problem has always been to get good projects, and I still feel that way. We have access to capital like crazy at surprisingly low rates, and I don't really worry about the debt ratio or anything like that. What I worry about is good projects with good payouts, and we haven't had a problem financing good projects, and I doubt that we ever will, depending on, of course, on our disciplined definition of a good project.

Okay, I guess the only -- the one thing missing in that equation is that maybe because of the level of debt you have, the ability to take advantage of the market's negative swings like we have seen, and with the stock down so much, you don't really -- the flexibility to buy in shares is probably more, not all that great relative to what it could be and had been in the past.

Yes, but I don't think that's -- it is a little bit a function of debt, but there are other constraints limiting how much of your shares you can buy back, and maintain your credit rating kind of thing.

So, it is not a question of projects versus shares, it is really other issues, and not any different than it has been in the past, essentially?

I would say that is exactly right, and I would say we would infinitely prefer to have a good return on incremental capital that is deployed than buying back shares.

Okay, thanks, Gene. That is it for me.

Alicia, I think with that we'll end the call here. Thank you, ladies and gentlemen, for participating.

Ladies and gentlemen, that does conclude the conference call. You may now disconnect, and thank you for your participation.