Nabors Industries' CEO Discusses Q4 2011 Results - Earnings Call Transcript

Feb.22.12 | About: Nabors Industries (NBR)

Nabors Industries (NYSE:NBR)

Q4 2011 Earnings Call

February 22, 2012 11:00 am ET

Executives

Dennis A. Smith - Director of Corporate Development for Nabors Corporate Services Inc

Anthony G. Petrello - Deputy Chairman, Chief Executive Officer, President, Member of Executive Committee and Member of Technical & Safety Committee

Joseph Hudson -

R. Clark Wood - Principal Financial & Accounting Officer and Controller

Analysts

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Kevin Simpson - Miller Tabak + Co., LLC, Research Division

Ole H. Slorer - Morgan Stanley, Research Division

John M. Daniel - Simmons & Company International, Research Division

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Nabors Industries Ltd. Fourth Quarter 2011 Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Wednesday, February 22 of 2012. I would now like to turn the conference over to Dennis Smith, Director of Corporate Development. Please go ahead, sir.

Dennis A. Smith

Good morning, everyone, and thank you for joining us again. In addition to myself, this morning, Tony Petrello is with us, our President and new CEO, and he will be conducting the call today. Also in attendance is Laura Doerre, our General Counsel; Clark Wood, our Principal Accounting Officer; and essentially all the heads of all of our various business units.

Today's call, we're going to take a lot of extra time to not only review the quarter and the forward outlook, but talk about a lot of more specific information, a little bit of our plans that are in motion. And as such, in support of that, we put some slides on the website. That's on our website. You can find them if you want to follow along, and Tony will referring to them, a few, as he goes. It's at nabors.com under Investor Information, and then under the sub-menu under Events Calendar. You'll find it where the conference call is listed with the discussion.

As I said, we'll limit the call as we usually do to about an hour. The remarks will probably be more like 45 minutes today, so we'll have a limited time for questions and answers, but we'll try to get to as many as we can. And with that, I want to just remind everybody that obviously a lot of what we're talking about is forward-looking and subject to change as the market goes. We encourage you to read our 10-K and 10-Q filings for all the risk factors that are involved with that.

And with that, I'll turn it over to Tony to get started this morning.

Anthony G. Petrello

Good morning, everyone. Welcome to the conference call, and I want to thank everyone for participating. As Dennis said, we have posted to the Nabors website the slides, please refer to them. And as he also said, I expect to be going on a bit longer. Hopefully, I intend to address much of what is on your mind. And if I don't get it right, I apologize.

Before we begin a review of our fourth quarter and recent developments, I would like to share with you some of the reasons why I'm so excited about the opportunities that are available at Nabors. This quarter, every player in the sector is focused on exploiting their liquids-rich market position given the respective gas and oil commodity prices. Think back just 4 years ago how everyone was exploiting their operating leverage to U.S. gas. Things change often. Today, everyone is also focused exploiting their competitive advantage because of new equipment, whether that is new spec rigs or frac spreads. But as we know, commodity prices change and ramp-ups eventually ease.

Today, when you look at where the operators' investment is directed on a large scale basis, whether that is in deepwater or in the shales, there is a common denominator, the desire and ability to invest in projects that can provide a reasonable return for the duration. Successful execution of these projects require that they be done in a safe, predictable and consistent manner. While access to new fit for purpose equipment is often optimal or even necessary in certain applications, they are in the end just tools.

The real need is to have organizations that have resources, power, processes and know-how that can deliver reliable and safe solutions that address the real risk factors economically and in today's world, on scale. And the challenge is to do this in an industry that is talent-starved and keenly aware that everything it does is subject to increasing public scrutiny.

Nabors today, in my view, is in a unique position to grow in this role. We have a large footprint in many of the development markets. We have quality assets, financial resources and human capital, all on a global scale that is really unique in our space. We have built an infrastructure that can provide the operator of today and tomorrow with a level of support and risk mitigation that assures their projects require. And we now have a record, which I will elaborate on in the unit reports, of technological leadership that increasingly is being noted by our customers.

We are committed to expand and build upon that expertise. We will focus on operational excellence and using our considerable asset base and know-how to drive operational performance. We hope to use the technology tools that we now have available and are committed to develop further to enhance the value proposition for our customers, provide challenging opportunities for our employees and create superior returns for our shareholders.

Now this focus requires us as an organization to address some of the missteps, which I think we've been pretty candid about, that we have to respond to and move forward to get where we want to be.

If you turn to Slide 3, that speaks to our priorities. Accordingly, we have first, commence steps to monetize our E&P assets on a prudent basis. We're obviously focusing on the oily assets. As you all know, we have an Eagle Ford asset. That process is underway. We have an asset in Alaska. That also is underway because our joint venture partner is looking to monetize as well.

Second, we've initiated a review of ancillary businesses and assets that are not meaningful contributors. Here, the objective is a straightforward one: to focus the company's effort where effort is worthwhile and where results are meaningful. Slide 6 identifies the common sense factors we'll use to evaluate each of these ancillary businesses. And I think you're all familiar with them. They range from construction to rig moving and an assortment of other things.

Third, tightened capital. One of the things that hasn't changed in 20 years, and that will not change, is our view that the company should only invest in transactions that would make sense to us personally. Respect the company's money like your own. Invest for real returns: that is the goal. We have gotten some wrong along the way, but the philosophy continues. We believe that the size we are now, we can high-grade those choices and demand greater selectivity. This need for capital discipline will apply to both new additions, as well as sustaining capital. Moreover, we need to develop some further internal systems to support and bring the accountability for all these decisions.

Fourth, starting a review of simplifying how we deal with our customers. Broadly, our scope of services consists of 2 primary lines of business as shown on Slide 7: drilling and rig-related services, which involves all activities involved in well construction; and second, completion of production services. This line is composed of Pressure Pumping, workover in well services and fluid management, services that complete and maintain the well.

We are looking at ways to reorganize our operations along these lines to allow for operational cost-saving synergies and a better interface to our clients. Many of our large customers, of course, are organized in this way, and we think that will facilitate the interface. During the remainder of this year, I’d hope you all see the benefits of some of these changes I'm talking about.

Now let me turn to the fourth quarter financial results. Nabors had a solid fourth quarter, driven primarily by good results in our U.S. and Canadian drilling operations and our Pressure Pumping operations in Canrig and to a lesser extent, in our Alaska and U.S. offshore operations. These results more than offset the seasonal decline in our Alaska logistics and trucking entities and the anticipated drop-off in our international operations.

GAAP net income from continuing operations was $89.5 million, about $0.30 a share in the fourth quarter and $1.17 per share for the full year. Non-GAAP net income was $153 million, $0.68 a share in the fourth quarter and $1.63 per diluted share for the full year. Adjusted income from operating activities was $272 million, bringing the total for 2011 to $927 million. This compares to $224 million for the corresponding quarter of 2010 and $668 million for all of last year. And revenues for the company were $1.7 billion for the quarter and $6.1 billion for the full year.

The quarter's GAAP income from continuing operations includes a $100 million charge or $0.22 a share for the announced contingent liability that existed on December 31 related to Gene's departure agreement, notwithstanding that on February 6, 2012, we made the announcement that Gene had elected to forego triggering that payment. Gene wanted to give it up. The accounting people didn't want to give it up basically, and so that's the reason why that charge is there.

Our press release based on review of early reports this morning may not be clear on the subject of the $100 million charge. Gene has waived that amount, and it will not be paid to him. The reason for the charge is that we had been advised his entitlement to that amount on December 31 required us to take the charge in the fourth quarter even though he waived it in February 20 -- in February of this year. We are not making a $100 million gift to charity.

As we stated, we are contributing 1 million common shares of Nabors stock to a charitable foundation for the benefit of Nabors employees and other causes. The accounting consequences of Gene's waiver and of the contribution will both be made in the first quarter when they occurred. And as we've mentioned, a substantial part of these funds will be used for Nabors employees and their families for education, as well as other issues. And one of the thinking behind this was since the employees are going to benefit, funding this with non-cash Nabors stock gives an incentive of everyone in the company to help drive stock performance. So that's part of the thinking that's gone into this.

Now before getting into the specifics of the business units, let me address some preliminary matters, our balance sheet. As you can see on Slides 4 and 5, our balance sheet is solid with leverage at 2.2x our annualized fourth quarter EBITDA, down from as much as 3.5x in recent years. Total debt at December 31 was $4.6 billion, with $540 million in cash and investments. This reflects a slightly higher revolver balance than last quarter as we are at a temporary peak in previously committed capital expenditures. This is obviously higher than where we want to be, and our goal is to eventually get below 25% on a debt-to-cap basis.

The primary way we intend to reduce net debt in the short term is to monetize the E&P assets as expeditiously as possible but in a prudent manner. More than 90% of our term debt maturities are 2018 or longer as shown on Slide 5. Monetization of other non-core assets is a possibility, but the best way in our view is to instill more stringent capital discipline in order to generate consistent free cash flow from operations.

Second general topic, taxes. Let me take a minute to talk about that. Our reported effective tax rate from continuing operations for the fourth quarter was 20.9%, with the rate of 29.3% for the year. This lower-than-expected tax rate for the quarter is the result of 2 drivers: first, the $100 million charge for a payment that will not be made; and second, also a favorable tax adjustment in certain venues. Without the net effect of the $100 million charge, the tax rate for the quarter would have been 28% and 30.4% for the year. This yields the $0.52 earnings per share for the quarter for continuing operations. In other words, the announced $0.52 earnings per share for continuing operations without those charges is a number normalizing away the $100 million charge.

In terms of 2012, here's some guidance. We expect the rate to be 33% or 34% before continuing operations. Even though we expect our international operations to grow significantly, a effective tax rate of 14% to 16%, this will be outweighed by the increase we expect in North American operations, where the effective tax rate is 38% to 40% and generally, 27% to 30% in Canada.

Third topic, capital expenditures. Capital expenditures for 2011 totaled $2.25 billion roughly, which includes acquisitions. Depreciation is about $925 million. For 2012, depreciation is scheduled to be about $1,070,000,000. Capital expenditures currently planned for 2012 total about $1.5 billion. That number may go down with further scrutiny. It also may go up if we're fortunate enough to get an additional quality opportunity. But I think you'll notice when you go through the slides, you'll see a couple rigs -- spec rigs in the U.S. has been dropped off our schedule.

Two additional general points: fleet quality and availability. Our fleet quality is very high. Slide 9 shows just our AC rig fleet. Many of these rigs are not in the U.S. land drilling market and drive margins that are a multiple of a U.S. land rig. We also have the world's largest fleet of upgraded SCR electric rigs, many of which possess essentially the same functionality of an AC rig. That's, in fact, one of the benefits of the Canrig Technology of using a proprietary K-box and adding it to an SCR rig that gives it equivalent functionality. And we have that on many of the SCR rigs and, in fact, on some mechanical rigs.

The second general point, run rate. If you look at Slide 10, it shows 2011 and fourth quarter operating cash flow annualized run rate compared to our highs of 28. The point here is that we're now getting back on track where we have a rate that exceeds our prior high, and we still have a lot of room for further improvement. And hopefully, that will become clear as we go through the business unit reviews.

Slides 11 and 12 give you more detail on the quarterly results for each of the business units that we customarily provide to in these calls. Now let me go through some of the business units.

Nabors USA. Our U.S. drilling operations reported operating income of $130 million, up from approximately $105 million in the prior quarter and $85 million in the fourth quarter of 2010. This was the result of an increase of 15 rig years, plus $746 in the average margin per rig day. The rig count increase consisted of 6.6 rig years from 8 new built rigs we deployed in the quarter, plus 4 rig years from 6 deployments of recently refurbished rigs, as well as another 2.4 rig years from 4 startups of idle but ready-to-go rigs. Our average margins for the fleet averaged 10,922, which was a composite of about 12,500 for AC rigs and 9,600 and change for our other rigs.

The quarterly margin improvement reflects an increase in revenues of $812 per rig per day, which was partially offset by higher operating costs of $66 a day. First quarter margins will likely be flat as they are subject to a negative swing of roughly $500 per rig, as you know, for customary payroll taxes that we have kicking in, in the first quarter. And we reset our worker compensation accruals each year. We typically realize a benefit of that from a good experience return in December, so that accounts for why there will be that swing.

We are cognizant of the weakening national -- natural gas market, and we think it is reasonable to assume that the industry rig count will at best be flat and could well decline in 2012. There could be more downward pressure on spot rates. At present, leading-edge rig rates in the Rockies, the Bakken and the Northeast are 27,000 to 30,000, while rates in Texas, the Mid Continent and the Gulf Coast are slightly lower at 24,000 to 25,000. Rates have recently been flat at most areas with the exception of the Haynesville Shale in East Texas and Louisiana, where we believe they are down about 5%.

We are also seeing the average duration of term renewals get shorter. Nonetheless, our contract backlog continues to increase, further mitigating the weak gas environment as you can see on Slide 14. If you turn to Slide 14, here you see the number of take-or-pay contracts that were enforced at the end of the year and those that will be enforced at the end of next -- of the next 4 quarters based upon what we know for certain today. If you compare this to the same slide we posted at the end of the third quarter, the 144 contracts enforced at that time increased by 42 contract signings to the 186 shown now, replacing the 19 expiring contracts and adding another 23.

In other words, each quarter, we are nevertheless signing more new contracts than those that are expiring, so our backlog continues to grow and now exceeds $1.2 billion in gross margin. And I'd like to emphasize that those are real-term contracts. These are not contracts that you can cancel with 90-day cancellation and incur no penalty. When we talk about a term contract, it's a term contract whether it's 6 months, a year or 3 years. They typically have provisions that protect your cash flow.

Even in a moderating market environment, operating income for this operation should therefore be up in 2012 compared to 2011 as average margins for the 25 new build rigs we expect to deploy in 2012 are much higher than those obtained from our gas-vulnerable rigs. When we look at our portfolio of rigs, we see approximately 35 that are drilling for dry gas and that are not subject to take-or-pay contracts. They are mostly in a fuel-vulnerable market, including the Piceance Basin in Colorado, the Haynesville shale in Louisiana and to a lesser extent, the Marcellus in Pennsylvania.

Now at one point, we had 58 rigs drilling in the Haynesville, and that number is now down to 26, 14 of which are drilling for dry gas without a term contract. A few of these rigs are already scheduled to move to oil-directed regions, an ongoing trend that you see by us and everyone else.

Our results sensitivity to change in gas rigs could be evaluated as follows. If you assume 20 of the rigs drilling for dry gas all cease operations at the beginning of the second quarter and do not resume for the remainder of the year, then the negative impact on Nabors would be on the order of $50 million. While this is a significant number, it represents less than 3% of our 2011 EBITDA and probably a smaller percentage of our 2012 EBITDA. Our market position is strong, with a significant presence in all of the best markets. Slide 15 shows the regions where we operate and the number and type of rigs we have in each area.

Now we continue to see interest in new builds in this unit, although the operators’ weaker cash flows resulting from low gas prices are delaying some plans. As shown on Slide 16, we have 25 new builds planned for deployment in 2012, 21 of which are governed by long-term contracts. This will bring the total number of new builds in the U.S. fleet to 144 and the global new build fleet to 215. As you can see from Slide 16, our new build AC and upgraded SCR rigs will account for 71% of the U.S. Lower 48 rig fleet, with standard SCR rigs and competitive mechanical rigs now comprising only 29%.

While new build AC rigs will continue to be preferred and may be required in many applications, the market for legacy rigs is not disappearing. Moreover, with technology upgrades at legacy rigs, like the proprietary K-box I mentioned, AC top drives and upgraded pumps, that may well extend those legacy rigs and their value proposition for the customers.

I'd like to turn to Nabors Canada now. The operating unit for this -- the operating income for this unit in the fourth quarter was about $37 million, up from about $22 million in the prior quarter and about $17 million in 2010. The quarterly increase is principally due to a sequential increase in margins of $1,700 and change per rig day as we moved into the winter season when results typically are supported by peak seasonal demand and additional content.

The doubling of results compared to the fourth quarter of last year was attributable to additional 6 rigs working at margins that were almost $3,000 a day higher, which is indicative of the ramp-up in this market. Now obviously, we had a very strong quarter and prospects continue to look good, driven by the same dynamics that characterize the U.S. market, namely the shift away from dry gas and towards oil and liquids.

As shown on Slide 7, we have a concentrated asset base in the shale plays and in the conventional oil markets of Alberta and Saskatchewan. We estimate that 85% of our rigs are active in oil and liquid-rich basins in Canada. We also have incremental work in the Cardium and now are commencing work in Alberta and Saskatchewan-based Bakken shales.

In the fourth quarter, 2 new slant service rigs were deployed in the oil sands and we expect to deploy another 2 in the first quarter of 2012 when we will also deploy 5 upgraded drilling rigs to other fields. We had a busy winter in the Horn River in anticipation of the sanction of the LNG export capacity in the not too distant future, something we also hopes improves our marketability of our Horn River assets. That ramp-up has been dampened somewhat by weak gas prices, which is also affecting activity in the Montney. Interest in new builds continues in this market.

But because contract terms in Canada have a shorter -- typically a shorter work season, they often do not yield the returns that are as attractive as we obtained elsewhere. And so we've become increasingly selective in availing ourselves of these opportunities. Basically, as I'll discuss later, in terms of capital, we're high-grading capital plus the business units, and we want them all to seek the best opportunity across the business units. And so that's one of the issues in Canada in terms of incremental rigs.

Nabors International. As expected, fourth quarter results in our international operations were down at $23 million and change compared to $29 million in the prior quarter and $72 million in the fourth quarter of 2010. Our rig count averaged 113 for the fourth quarter and stood at 116 at the end of the year. The exit rate represents an increase of 11 rigs compared to the third quarter and was 17 rigs higher than where we started the year.

Margins were down sequentially at roughly 11,000 and should remain at that level through the first quarter, after which, we expect to see improvement through the balance of the year. The lower margins of recent quarters are primarily a function of mix that is onshore versus offshore and more competitive environment and the extensive downtime associated with preparing many of our higher-margin rigs for new contracts.

The full deployment of this higher-spec rigs will improve our mix and should return us to the higher margins we achieved in 2008, when we averaged almost $15,000 per rig day. Now among these high-contribution projects are the December commencement of long-term contracts for 2 jack-ups in Saudi that were in the shipyard for much of the prior year; the late second quarter commencement of a new long-term contract for another Saudi jack-up, which entered the shipyard for regulatory check and upgrade at the end of the fourth quarter; the third quarter restart of 4 land rigs, which were being upgraded for new long-term contracts in Saudi; the second quarter commencement of operations on a new platform rig in India that is currently being mobilized and rigged up; and the second half contribution of 2 high performance, environmentally efficient land rigs in Southeast Asia; and then there's an assortment of other miscellaneous rig start-ups and venues during the second half. All of this should bring our exit rate to 130 rigs by year end and positively impact our average margins well into 2013.

I should add here that both our land and offshore markets internationally have become more competitive due to new entrants and speculative rig additions. We will respond by focusing on the type of projects that Nabors can uniquely do and that give us an edge. We believe that with increasing interest by operators, not only the large international companies but also some of the NOCs, there will be sufficient opportunities to make good returns in investment capital and nevertheless grow.

We have already tightened the hurdles for further capital investment, while CapEx in international is being throttled back, sustaining plus additional capital to 75% roughly of our depreciation for 2012. The benefit of this shift in focus should manifest itself in late 2012 and beyond.

Nabors Offshore. Our U.S. Offshore operations reported operating income of $3.4 million, up from $2.5 million in the prior quarter and significantly up from the $5 million loss recorded in the fourth quarter of 2010. The Gulf of Mexico market is improving very gradually, and we are putting back rigs back to work. We're encouraged by the number of jobs still awaiting government permits, and these are jobs which we think Nabors is in a well positioned -- to garner.

We continue to be the leader in proprietary and innovative offshore rig designs. Our Sundowner rig, I think it's fair to say, revolutionized the shallow water workover sector. And we built on that technology to develop the first MASE rig and then the MODS rig designs that allows us to rapidly expand into deepwater. Our experience in developing and deploying these rigs is why we were selected to construct 2 new state-of-the-art 4,000-horsepower deepwater platform rigs, the largest ever constructed for work in the Gulf of Mexico for 2 supermajors.

Now when you all think of Nabors, you don't normally associate Nabors with deepwater. But the fact is we have 8 deepwater platform rigs working the Gulf of Mexico, by far the largest position. Our market penetration will be further enhanced when we roll out these new rigs, and so it's safe to say this is a position we really want to build upon. And thanks to the offshore engineering talent, we think we can be competitive and maintain very attractive returns on capital. This is an example of the kinds of projects where Nabors has an edge.

Results in 2012 should improve with the full year's contribution from the deepwater restarts in 2011, plus new projects that are likely to begin in 2012 as permitting eases mostly in shallow water. We will also receive increasing larger payments from 1 of the 2 4,000-horsepower rigs we are constructing. All of this should have a positive impact as we go forward in 2012.

Nabors Alaska, this year posted results of $5.3 million, up from about $3 million in the prior quarter but down from approximately $11 million recorded in the fourth quarter of 2010. Lower overall drilling activity impacted 2011, and we believe a modest turnaround is in process and could be more meaningful with time. The modest improvements and results in the quarter were derived from increased activity. The first quarter is off to a good start as a result of Nabors being awarded the majority of the work for what is turning out to be a pretty busy winter exploration season. While we anticipate that the usual seasonal slowdown in activity in the second quarter, there are a number of pending projects, both onshore and offshore, 2 on the North Slope and several in the Cook Inlet basin where we are in a good position to participate.

Additionally, if the Alaska legislature enacts some reductions in tax progressivity before adjournment in mid-May, there is some pent-up demand in large legacy fields on the North Slope that could materialize, perhaps as early as late this year. This could also generate opportunities for our proprietary North Slope coiled tubing drilling rig, which has been very successful. And I'd like to say that the Alaska administration seems to be very aggressive about wanting to bring additional players up to the slope. They're really doing -- they've attracted a bunch of midsized companies up there. And if this tax change does go in effect, I think they'll have a real good pitchbook to attract some additional people up there, which I think is really good for us given our position up there.

Superior Well Services. Results of about $77 million in our Pressure Pumping operations were up from $65 million in the prior quarter and $55 million roughly in the fourth quarter of 2010. Operating income for the full year was $229 million, which cannot be meaningfully compared to 2010 since we owned Superior for 1/3 of the year then.

This quarter's nearly 10% improvement in sequential operating income margins represents good progress towards our goals. We expect further improvement as new crews become more efficient as we continue to improve our transportation, logistics systems in the face of a doubling of throughput in less than a year. While we believe there is further room for margin increases, it should be noted that there is a high degree of variance in this important measure across our various regions and also across our competitors' numbers that you all analyze. The variance stems from seasonal constraints, which markets people are in, labor availability, depreciation metrics and cost bases.

This is illustrated by the fact that while we average less than 20% in operating income margins for the year across the board, our margins from the Eagle Ford were more than 45% on this metric. Similarly, like some other companies who primarily work in the Eagle Ford, we too enjoy revenue per stage in that market on average more than $200,000. This proves that the SWSI unit can deliver top-tier results as well.

Three incremental spreads were deployed during the fourth quarter, one in the Marcellus and 2 in the Rockies/Bakken shale. This brings the total number of large crew spreads at year end to 22 and total hydraulic frac-ing horsepower to 733,000. If you will turn to Slide 19, you will see where this horsepower is located and where it has yet to go.

Slide 20 gives you more details on our current contract position and where rates are trending today. The decision to operate on a 24-hour basis is typically basin-specific. The Marcellus, Bakken, Eagle Ford and Granite Wash have the majority of the 24-hour operations. We currently have 40% on a 24-hour basis and plan to increase that percentage.

Moreover, if you would turn to Slide 8, you will see we try to position each of our product lines together with SWSI in basins where they can complement one another. And that's going to be consistently one of our strategies. In fact, we will be building out our infrastructure in these locations to co-locate the various product lines together to achieve some cost efficiencies.

Today, our largest operation is in the Bakken/Rockies with 9 spreads working at year end. Spread 10 commenced operations in January and spread 11 is scheduled to arrive in May. When fully deployed, 73% of our equipment will be on term contracts in this area. Eagle Ford represents the next largest position, with 4 crews working. We have no plans to expand further in this area as it is rapidly becoming the most competitive of all of our markets. Fortunately, 1/2 of our equipment here is subject to long-term agreements at attractive rates. The Marcellus has always been a core area for Superior, and we just deployed the fourth spread there in January, with 3 of these spreads working in the more liquids portion of the play and a long gas-directed spread committed under a long-term agreement.

The balance of the fleet consists of 3 spreads in the Permian basin, with one on long-term contract and one each in the Barnett, Granite Wash and Haynesville shales, the latter of which is the only dry-gas-directed work we currently have that is not subject to a long-term contract. These additions will bring the total hydraulic horsepower to 857,000 plus 100,000-horsepower for cementing nitrogen and acidizing.

As Slide 19 indicates, we also have a decent position in cementing and coiled tubing. We have no plans to add in 2012 hydraulic frac-ing capacity beyond current levels or to add other equipment beyond the additional coiled tubing units than as many units I've already mentioned. The primary issue facing the industry today is the continuing deployment of what may prove to be excess capacity under weakening margins. Potential shrinkage of demand for hydraulic frac-ing in gas-directed markets is likely to exacerbate the situation. However, in the case of Nabors, I believe these factors will be mitigated at least through most of 2013 and allow us to continue to derive healthy returns on our investment in this business.

The reasons for this are the following: First, we have limited contracted exposure in most competitive areas. In total, we have 14 long-term service agreements in place that have take-or-pay provisions and only one spread, the Haynesville, exposed to dry gas on a short-term contract. In the aggregate, 72% of our expected 2012 operating cash flow from Pressure Pumping is secured by firm, long-term contract commitments. Again, these are real contracts with real termination provisions with a very, very substantial amount of dollars.

Another factor that works in our favor is the degree to which we can continue to improve efficiency in our operations. In 2011, we spent roughly $120 million in transportation and logistics-related costs, with nearly $20 million of that related to demurrage and incidental costs. That provides the ample opportunity to improve as we continue to incorporate the pumping operations into Nabors warehousing and transportation and purchasing systems. Longer term, we believe we have good opportunities in multiple venues outside of today's markets. Argentina and Oman are examples. Once we demonstrate our ability to operate efficiently, we expect to see further developments in the international market.

Next, I'd like to turn to Nabors Well Services. Our Well-servicing operation posted $24 million in operating income, a slight improvement over the $22 million we posted in the third quarter. This was contrary to the normal seasonal drop with holidays and shorter daylight patterns. Benign weather allowed this unit to generate an 11% increase in truck hours, a 3% increase in rig rates and a 2% increase in truck rates, all contributing to this improvement. At the end of the fourth quarter, our operating fleet consisted of 548 well service rigs, 921 fluid service trucks and 3,700 frac tanks. Slides 21 and 22 give you a more detailed view of the breadth of our services and market positions.

Going forward, we expect the first quarter of 2012 to be down slightly due to customary seasonal issues. This will be mitigated somewhat by the continued rate improvement in both rigs and trucks. The second quarter should represent a sharp rebound as utilization and pricing improves for both rigs and trucks in oil markets, namely the Bakken, the Permian, Eagle Ford and California. By the end of the second quarter, all 9 of the remaining advanced well-servicing rigs will be deployed in California. In addition, 50 fluid service trucks and 900 frac tanks will also commence take-or-pay contracts throughout the second quarter and will be fully deployed throughout the second quarter.

The positive effects will be dampened, however, by reduced contributions from our Northeast operations due to the soft gas market and weather-related issues. We will continue to identify and exploit synergies in logistics and fluid hauling within our Pressure Pumping operations. Additionally, with a significant increase in oil-related drilling in the Lower 48, the future demand for well-servicing rigs continues to increase. We believe we are strategically positioned in most of the oil-rich areas to satisfy this demand.

On our Other Operating Segments, this unit posted results of $13 million, down significantly from the $20 million reported in the third quarter but up from the $9 million reported in the fourth quarter of last year. This was primarily attributable to seasonally low results in our Alaskan logistics and construction entities and weaker results in our directional drilling business, which collectively more than offset record results in Canrig. Canrig's strong performance is attributable to higher rigs -- higher revenues, excuse me, in both its capital equipment and service and rental lines, and it was achieved in spite of $4 million in research and development expenses it incurred on a non-preliminary basis.

Canrig's operational results actually increased 25% sequentially and 68% year-over-year when we exclude the $4 million R&D expense. We continue to be optimistic about Canrig's potential going forward with its potential for product sales and its technology initiatives. Some of these are outlined in Slide 23. During the year, we deployed our 1,000th top drive. I might add that top drive #1 is still in the field. We also doubled our production of top drives to 120 this year. The number of catwalks and wrenches had equally impressive doubling of production.

Canrig also installed the 200th ROCKIT system, which increases the rate of penetration and connection time during directional drilling. It commercialized our REVIT Stick-Slip product, which stabilizes rotational torque and installed that on 45 rigs. It acquired a GE distributorship agreement for AC drive systems, which will lower our costs and improve the reliability and technical capabilities of many of our products. It acquired world-class management -- managed pressure drilling technology through a license agreement with MPO, which we will be looking at rolling out, and successfully managed an automatic driller that allows setting of drilling parameters remotely by an operator using proprietary algorithms to optimize performance.

We also continued to successfully file and defend a broad range of patents that now stands at over 100, and we expanded our support and operations line to improve performance for ourselves and Canrig's customers at a 24/7 manned round-the-clock center.

We believe there's another step change in drilling technology on the horizon in the form of more automation of the drilling process and increased remote monitoring and control. Canrig's AC top drive and rig controls and its IP, we think, will provide an advantage for Nabors as we move forward in that environment.

Briefly, Oil and Gas. The Oil and Gas was down $3.4 million from the $7.7 million reported in the third quarter when we exclude the $27 million of non-cash gain from NFR in the third quarter. This segment now consists of only NFR as all other holdings have been reclassified as discontinued. As we stated in our press release, we decided to take further impairments and reserves against these holdings, principally those in Canadian gas, in an effort to achieve what we believe is a conservative valuation under today's market conditions.

We have initiated processes to sell our various properties, as I've mentioned. Obviously, the current environment for the gas properties, this may take some time. One remaining issue is that we will likely in the next few quarters still face further ceiling impairment tests from NFR as the 12-month rolling average gas price methodology is on a downward trend.

So in summary, I'd just like to say, Nabors has a tremendous opportunity at hand, both to grow the business and command investor confidence. The priorities I outlined at the beginning of this call should result in a meaningful redirection of the company and improve performance. We have the resources to make it happen. We have a great asset base that is global. We have great tangible assets, as well as intellectual capital. We have sitting with us, one of the deepest experienced management teams, I think, of any company. And we have a 20,000 strong workforce that's enthusiastic and willing to embrace the changes.

I apologize for the length of the remarks, and now we'll take your questions.

Dennis A. Smith

Flo, we're ready for the question-and-answer session please.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Jim Rollyson with Raymond James.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

You mentioned at some point getting back, you were hoping, to the 2008 level margins on the international front, which were in the mid-teens. When you kind of look at where you stand today and getting to the 130 rigs that you -- exit rate you were talking about, where does that put you on for margins if everything goes as planned and kind of when do you think you might get back to that mid-teens level?

Anthony G. Petrello

I think during -- as I mentioned, during the first quarter of 2012, we're still at a plateau level. Then it starts -- it will start to ramp up in the second quarter, and that should accelerate toward the end of 2012. By 2013, that's when I think we can hope to approach that level. I think one of the questions -- one of the things that's hampering that number is obviously the jack-ups were -- these numbers, of course, are all blended between land and offshore, which makes it a little difficult. But the jack-ups have been locked in at numbers, and they're on term contracts. So we need to offset some of that. But by the beginning of 2013, I think that’s where we see getting those ranges. And of course, on new projects, the discipline in terms of allocation of capital to anything new, we're going to try to be pushing to rates where we want to get to.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Sure, that's helpful. You mentioned in your prepared commentary, operating cash flows this year will fund CapEx, debt redemptions and provide free cash flow. Is that including asset sales or would asset sales just basically be icing on the cake?

Anthony G. Petrello

Well, the aspiration is to do it before asset sales. So -- but like I said in the press release, we have this number of $1.5 billion currently on the table for CapEx. It's still subject to some scrutiny. And if that holds and the plans I have mentioned hold as well, there should be some free cash flow away from asset sales.

James M. Rollyson - Raymond James & Associates, Inc., Research Division

Okay. And the last question for me. When you think about capital investment right now, and obviously you're taking a look at rationalizing your asset base starting with Oil and Gas and other things, are you focused on doing the rationalization first? Does that preclude you from considering anything on the M&A front or are those functions kind of mutually exclusive?

Anthony G. Petrello

I think with respect to the former, we have a sense of urgency about it, but it is not exclusive of the second category. So in other words, we will think in parallel terms, and I think we have to in today's world.

Operator

And our next question comes from the line of Kevin Simpson with Miller Tabak.

Kevin Simpson - Miller Tabak + Co., LLC, Research Division

Tony, maybe you can -- I don't know if Joe is there, just swing it over. I'm just curious as to the current tone in the marketplace with -- obviously with gas prices down, which you've already spent a fair amount of time on. But I'm just wondering if you guys are now beginning to see companies back off from prior plans, rigs that you thought were going to get renewed, not renewed or are you still able to find homes for everything that gets -- like go on the rig side? And I guess -- and also to some degree, in terms of activity in the frac business.

Anthony G. Petrello

Sure. I don't think Kevin is -- it's kind of an interesting world where we do have a $100 oil price and you have a bunch of companies, for example, who are looking to deploy capital. And historically, they deploy capital because they need to find places to spend large amounts of money and capitalize on that kind of oil price, and they typically have gone international. So given that that's out there, that thinking, the fact that there's still $100 oil, you would think that the fact that the gas price is low doesn't abate, in fact, ought to cause people to continue to think of U.S. as just another place to continue that process. Anyway, Joe will -- he recently held some talks with some people, so let him give you the color.

Joseph Hudson

All right. Thanks, Tony. Kevin, I looked back at the transcript from July and you asked me then what my vision was looking out. You said, "Is it a 10?" I said, "No, it's a 7." And I said, "30 years of experience tells me things change." Now the term contracts we have in place are partially a result of that. And you asked about the rollover. So far, we've been able to put most of the rigs to work coming off of existing terms, whether it's an extension with a current operator to a new operator, et cetera. So we've been pretty fortunate with that. We -- as Tony mentioned, I attended a function Sunday night at a large independent, did a presentation. Their thoughts, the rig count isn't going to change dramatically in the U.S. And the comment was -- yes?

Kevin Simpson - Miller Tabak + Co., LLC, Research Division

It’s not, you said?

Joseph Hudson

Yes, is not going to change in the U.S. What they're doing, they're redeploying, as Tony mentioned, dollars into Oil and Gas. And the comment was by their CEO, as long as $100 oil is here, they're going to work. And he says, hopefully, we don't drill ourselves out, like we did with gas, with oil. But the bottom line is, there's a lot of future ahead with oil. We're redeploying assets, as Tony mentioned, from different areas into the oil plays. We've recently put our first rig in the Utica, which came out of the Marcellus. We put 3 rigs up in what they call the Mississippian shale, which is in Kansas. So we've seen deployments. Most of those rigs came out or will come out of the Haynesville, so there's a lot of opportunities still going forward. Not saying again and say, as I told you in July, a 7 out of 10 as far as the vision.

Kevin Simpson - Miller Tabak + Co., LLC, Research Division

Good. That's great. And just one quick follow-up. You did mention in the release, Tony, that there were some new build -- still new contract opportunities. Could you -- it sounded like that was in the U.S., I think it was. Is that -- are there still -- are you far enough along that you can kind of project out that when you do the next call, the one after that, that you will have signed some new contracts up even in the environment we're in?

Anthony G. Petrello

What I like to talk about is things that are done. When something’s done, we'll talk about it. And we're hopeful, and that's something we're pursuing daily with lots of people. So -- but nothing to report right now.

Kevin Simpson - Miller Tabak + Co., LLC, Research Division

Black and white, no projections. I get it.

Anthony G. Petrello

Right.

Operator

And our next question comes from the line of Ole Slorer with Morgan Stanley.

Ole H. Slorer - Morgan Stanley, Research Division

One thing that struck me, again, going back to the 35 rigs that are locked on take-or-pay. I mean, even rigs, I presume, that are on take-or-pay contracts will have customers trying to move them from gas to oil. So how many of those rigs do you have in gas do you think are capable of moving to oil?

Joseph Hudson

The 35 rigs, they're all currently operating, so they're all fungible assets.

Anthony G. Petrello

[indiscernible] size, so 1,500.

Joseph Hudson

No. And a majority of those can because, again, a majority of our rigs, as Tony mentioned earlier, they’re 1,000-, 1,500-horsepower rigs that are designed to work in almost any basin. So they're all fungible assets.

Ole H. Slorer - Morgan Stanley, Research Division

So there's not a disproportionate slant in the -- towards the, say, more vulnerable rigs in gas basins towards lower quality assets that could not be moved to...

Anthony G. Petrello

Not at all, not at all.

Ole H. Slorer - Morgan Stanley, Research Division

Okay. So the second question then would be, how long time do you think it will take -- if your mix is now 35 rigs not under take-or-pay, working in gas or -- let's say, we have a Haynesville, Marcellus, Barnett exposure of about 50 rigs or 20% of your fleet. I presume those are the most vulnerable areas for the rigs. How many of those do you think will migrate into oil basins through the year?

Dennis A. Smith

How many rigs do you think will migrate over to oil basin?

Anthony G. Petrello

About 35.

Joseph Hudson

Probably 35. Again, it depends. We're still -- we still want to compete in those markets, keep operations underway. But again, we already today redeployed some rigs in the last 2 weeks, 3 weeks from East Texas to West Texas where a very sizable operation is underway there. We moved some rigs recently from the Haynesville down to the Eagle Ford and are moving either 1 or 2 up into the Mississippian shale. So we'll continue to move as opportunities come up.

Anthony G. Petrello

Bottom line, he doesn't want to get pinned down. But right now, he's got 3 or 4 that are repositioning right now or in the next few months.

Ole H. Slorer - Morgan Stanley, Research Division

So how few rigs do you think will be required to drill for gas? I suppose there is some sort of a minimum level because of obligations. So is there a -- I'm just trying to figure out, at what point do you reach a level from which it is difficult to drop your gas rate count below?

Anthony G. Petrello

Well, I think that would depend on what's the base number for activity for gas drilling depending on the commodity price. There's certainly a number at which the whole thing goes through the floor. But I don't know what that number is, whether would a portion of that number that sets the floor for maintenance, as well as holding leases, et cetera. I don't know what that number is.

Ole H. Slorer - Morgan Stanley, Research Division

That's okay. The reason why I'm trying to get into this is that you made a statement, I think, that the total gas or the overall rig count would be flat to slightly down. And I presume that you believe the oil rig count will continue to rise, which assumes that you presumably had a pretty negative view on the net effect of the decline in gas rig count. That's what I'm trying to understand.

Anthony G. Petrello

Well, I think I said it was flat with potential to going down. And I think, on a cautious basis, that the deployment of the oil -- of rigs to oil should -- I'm not going to say it's going to overtake the decline but I think it reduces the rate of decline of the overall count. So that's the best we could say right now.

Ole H. Slorer - Morgan Stanley, Research Division

You also highlighted that the Eagle Ford was the weakest area, where you saw the most competition on Pressure Pumping. That was maybe a little surprising to some of us. Could you -- when did this become the most competitive market in your area? Was this a recent phenomena?

Joseph Hudson

I think Eagle Ford is a market that everybody has been focused on because, again, there's a lot of activity. I think what we're seeing is crews from the Haynesville, even some from Oklahoma, Barnett, have kind of focused on that area because it stayed active. So there's just a lot of people bidding on future projects. And now there's some new entrants into that play, and their goal is to keep the crews busy. So with that, they're just trying to find a way to get a foothold in that market. So for us, we've been there for a while. We've had some -- we got some good contracts in that market. And I think we just see that anything in the future that we're going to be bidding on has -- that there's going to be a lot of margin drop in those situations.

Ole H. Slorer - Morgan Stanley, Research Division

Okay. Finally, Tony, what's the book value now of the assets that you are holding for sale?

Anthony G. Petrello

Clark's got that.

R. Clark Wood

Yes, one second.

Anthony G. Petrello

You're talking about the...

R. Clark Wood

Yes, book value, about 2 seconds.

Ole H. Slorer - Morgan Stanley, Research Division

Yes, all the E&P properties, et cetera, you took some impairment charges [indiscernible].

Anthony G. Petrello

Net of all the impairments and everything.

R. Clark Wood

Yes, the net of what's all for sale is $275 million and then NFR is around $300 million.

Anthony G. Petrello

So it’s, say, it's $600 million altogether.

Ole H. Slorer - Morgan Stanley, Research Division

Okay. And you said that you don't rely on that in order for your -- or possible, in the $0.5 billion debt reduction target.

Anthony G. Petrello

We understand that. Cash is cash. Cash matters.

Operator

And our next question comes from the line of John Daniel with Simmons & Company.

John M. Daniel - Simmons & Company International, Research Division

You mentioned in -- this is for the Lower 48. You mentioned that flat cash margins in Q1 because of the, call it, $500 a day impact from payroll taxes and workers' comp. All else being equal, Tony, would you expect margins to jump $500 a day to get to Q2?

Anthony G. Petrello

Well, there's going to be an improvement. And Joe?

Joseph Hudson

Yes. As you mentioned, the $500, we call it, headwind we go into the quarter with. Because there, we think the second quarter, as mentioned, is going to be flat. It's really going to be determined on the pressure we see. We know -- we still have 21 new builds to deploy this year. All those rigs are going to be at better margins. So it really is going to be determined by what happens with the overall fallout and the gas count, which we don't know at this point. We know the term contracts were very well protected on the margin side. Eagle’s coming in and it's going to improve it. So again, we think...

Anthony G. Petrello

I think the short answer is we think a substantial amount of that will be offset, yes.

John M. Daniel - Simmons & Company International, Research Division

Fair enough. Just a couple on Pressure Pumping and I'll turn it back over. In the 14 long-term service arrangements today, is it safe to assume that some of those service agreements incorporate more than 1 frac spread, given that you've got 27 spreads? I'm trying to get to the 72% that's contracted.

Anthony G. Petrello

All right. The 27 -- first of all, those 27 includes Canada, so there's 25 -- so there's 2 up there, so there's 25 in the U.S. And then, of the 25, the long-term service agreements are on 14. I don't have the exact number, if you -- that’s by number. I don't have the exact number if you break it by horsepower related to the contracts what -- if the numerical 14 divided by 25, it’s disproportionate in horsepower, but it is 72% of the margin.

John M. Daniel - Simmons & Company International, Research Division

And then just last one for me, on the potential for margin improvement in Pressure Pumping. As you think about that, does that forecast incorporate any pricing reductions on the non-contracted work? And at this point, given that the market is getting a bit more competitive, have any new customers come to you to ask for you to amend contracts? And do you expect that to happen?

Joseph Hudson

The 14 contracts, definitely, we have some inflationary language in there where if we have inflation, we can pass that through. Some of the other spot market contracts, again, I think, at this point, we're kind of looking where -- if they're in the right spots, do we need to shift them around? There's still some markets holding up. And as we said earlier, we have a very high percentage between our contracts and oil basins that we feel like has a little better pricing than some of the dry gas areas. So a little overly detail, I think we're seeing E&Ps at this point, still evaluating where they want to be. And -- but I think we have a pretty high confidence in our position where we stand today.

Dennis A. Smith

Operator, unfortunately, we're out of time. I'm afraid we're going to have to suspend the questions there. If anybody didn't get their questions answered, feel free to call us. We'll wind up the call, please.

Anthony G. Petrello

Thank you.

Operator

Thank you, sir. Ladies and gentlemen, that concludes today's Nabors Industries Ltd. Fourth Quarter 2011 Earnings Conference Call. Thank you for your participation. You may now disconnect.

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