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 Joe M. Hudson - President David E. Wallace - Co-Founder and Chief Executive Officer

James D. Crandell - Dahlman Rose & Company, LLC, Research Division James M. Rollyson - Raymond James & Associates, Inc., Research Division Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Kurt Hallead - RBC Capital Markets, LLC, Research Division John M. Daniel - Simmons & Company International, Research Division

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Nabors Industries First Quarter 2012 Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Wednesday, April 25, 2012. I would now like to turn the conference over to Mr. Dennis Smith. Please go ahead, sir. Dennis A. Smith: Good morning, everyone, and I also want to thank you for joining our first quarter 2012 earnings conference call this morning. Our format today is customarily we do will be to have Tony Petrello, our President and Chief Executive Officer, provide with you with our perspective on the quarter's results and give you some insight into how we see our business and markets evolving. Following Tony's prepared remarks, we will open up for a question-and-answer for the balance of 1 hour and then limit the call to 1 hour. In support of his remarks, we posted some slides to our website, which you can access to follow along if you desire. These are accessible in 2 ways. If you're participating via the webcast over the Internet, they are downloadable right from that particular webcast website. Alternately, if you are on the telephone and -- you can access them from our website, nabors.com, under the Investor Relations menu; under that, the submenu Events Calendar; and you scroll down a little bit and they're right there in PDF format for you to download. With us today in addition to Tony and myself are Laura Doerre, our General Counsel; Clark Wood, our Principal Accounting Officer; and essentially, all of the heads of our various principal business units. As you all understand, much of our remarks, of course, will be forward-looking statements and as such, are subject to numerous risk factors as elaborated on in our 10-K and other filings. Since they constitute forward-looking statements within the meaning of the Securities Act of 1933 and '34, such forward-looking statements are subject to certain risks and uncertainties as discussed in our filings from time to time, and we encourage you to refer to those. And with that, I will -- now that the lawyers are smiling, I will turn it over to Tony. Anthony G. Petrello: Thank you, Denny. Good morning, everyone. Welcome to our first quarter conference call. I want to thank everyone for participating this morning. As Denny explained, we have on the website a series of slides. These slides contain details of our business, the performance of the various segments and other relevant information, and I'm going to be referring to them by the page number on the bottom right-hand corner. As you saw in yesterday's press release, we had a solid quarter, a prime example of what I think distinguishes our company. Before I go into the quarter's results and outlook, I would like to give you a brief overview of certain key initiatives I've previously spoken about and where they stand. First, E&P monetization. As you know, we are committed to monetizing our E&P portfolio as expeditiously but as prudently as possible. In addition to the previous year-end sale of our California properties, we have now sold our remaining Colombia oil and gas operation for $73 million, as well as certain residual holdings in the US Lower 48 for $4 million. These are summarized on Slide 3. To date, these sales total $149 million, which in the context of our overall investment is low-hanging fruit, but I hope reflects our commitment to get this done expeditiously. Slide 3 also lists the remaining E&P properties to be monetized. We have engaged investment bankers, as we've previously said, to market our Eagle Ford and Alaska properties. Because of the oil's nature, we expect we will be able to conclude sales on these properties before year end. On the tape this morning, I noticed that GeoResources has received a buyout from Alcon. GeoResources is our partner in the Eagle Ford. We are evaluating various avenues for our gas assets in the British Columbia shales and our NFR Energy joint venture. The current gas commodity environment makes that challenging, of course, but we are looking for any way to create value and we're open to all kinds of suggestions, if any of you out there have any. The timing is, of course, uncertain with respect to these gas assets, but they remain high on the priority list. Second, other asset monetization. As I indicated during our last quarter's call, we would review a number of our different asset classes and identify whether they made sense to retain them. We have, as a result of that, identified additional assets for divestiture. These are summarized on Slide 4. These assets include our Canadian aircraft business, hybrid coiled tube drilling rigs and our Canadian well-servicing operation. We have also decided to sell our Alaska oilfield hauling and services operation. We have engaged in a Canadian investment bank to help with the Canadian assets and we anticipate concluding most of this, if not all of these processes, in the second half of the year. We've also retained a U.S. investment bank for the Alaska assets. Additionally, during this process, we decided to sell off the remaining assets of our Peak U.S.A. oilfield hauling business in South and East Texas for $14 million. That was just completed this quarter. In addition, we reviewed our offshore position. We've decided our Gulf of Mexico jack-up barge rigs are not core, and the only issue is timing. We have also engaged an investment bank to provide estimates of market value on those assets. We are also still evaluating whether the international jack-ups, whether it makes sense to keep them as part of the core portfolio. And most of them, as you know, now have contracts. We're trying to assess the strategic value for key customers in certain markets, and we haven't decided one way or another yet. That's an ongoing process. Third topic, balance sheet. As we've previously stated, another area of focus is to improve our balance sheet flexibility. Slide 5 is a summary of our current financial position and also sets forth an aspirational target of where we want it to be within 2 years. We finished the quarter with $500 million in cash and investments. Our financial position is solid, with leverage now at 2.1x the first quarter annualized EBITDA and interest coverage of more than 9x that amount. Except for a revolver balance of a little over $1 billion and $275 million in senior secured notes maturing in August, our terms debt matures in 2018 or later. So I think we're in a very comfortable position in any times of uncertainty. Total debt does stand at $4.8 billion and our net debt to cap is 45%. The next 2 columns on this slide, to the right, set forth our targets to get to the net debt to cap of around 25% within the 2 years. We would like to accomplish this through a combination of sales of nonstrategic assets and increased capital discipline to facilitate the positive cash flow. The chart assumes getting there with only free cash flow generation, of course, depending on how the events proceed and roll out the next 2 years. Obviously, asset sales will accelerate this process, while also providing a cushion in the event of a weaker market condition in an uncertain environment. Fourth topic, organizational streamlining. We previously announced we want to modify our historical business unit structure to enhance efficiencies and improve our customer interface. We are now in the process of merging Nabors Well Services and Superior Well Services into one organizational structure. We expect that to occur over the next 2 quarters. With over 80 well-servicing locations and 35 pressure pumping locations throughout the Lower 48, we believe there is potential to realize both cost and operational efficiencies. We are also consolidating certain core support functions across the organization, moving to more of a matrix-type organization that you're all familiar with. In some sense, we've been in that position for a long time with the shared services environment, and I think we were one of the first of the service companies to go that route many years ago. Starting in May, we've hired a new Corporate Vice President of HSE and we'll be filling corporate positions in HR and subsequent to that, in engineering. Some macro comments before we get into our company specifics, and of course, when it comes to macro, all of you on this call are infinitely better poised to be a prognosticator as to what's happening. If I knew the macro for sure, I wouldn't be doing what I'm doing and I wouldn't tell you. That's for sure. Everyone is well aware of the weak natural gas environment and the potential ramification it holds for certain sectors of the North American operations, specifically land rigs and pressure pumping. As we mentioned in our release, we are seeing a degree of hesitancy on the part of customers with respect to initiating incremental projects, as well as an increasing contraction in activity in dry gas areas. As some of you may recall, we have previously stated that the second half of 2012 would see a flat to slightly lower rig count and diminishing demand for pressure pumping. Today, we also expect to see awards for new reconstruction moderating considerably. Slide 6 illustrates the trends in the weekly rig counts for oil, natural gas and horizontal wells since the beginning of last year. As you all are aware, the natural gas rig count was flat to modestly declining in October of last year, while the horizontal unconventional oil rig count was growing at a pace that outstripped the gas rig count, providing the overall growth in land drilling. Slide 7 breaks down the horizontal rig count between oil and gas wells. Starting in October, you see the rapid decline in the horizontal gas rig count is more than the increase in the horizontal oil rig count. We believe that the horizontal drilling is the best approximation of demand for both new rigs and hydraulic fracturing. The horizontal gas rig count will continue to be challenged in this commodity price environment, hence our view as to where we stand today. At the current oil price levels, however, we do not foresee a substantial sharp drop in overall rig activity, but we can see a sagging rig count well into next year. On the other hand, the impact on pressure pumping will likely be much more severe and protracted, given the excess pumping capacity and the number of new entrants that have to work their way out of the system. Nabors is in a differentiated position to weather these situations, as we have a healthy backlog of firm contracts in U.S. land drilling, as well as expected growth in our International, Canada, Alaska and U.S. well-servicing operations. Now let me turn to the first quarter financial results. Our earnings per diluted share were $0.65, with most of the sequential increase attributable to strong operational performance. The quarter did include investment income of $0.05 per share, which was about $0.02 per share higher than we realized in the fourth quarter. As we've previously indicated, falling gas prices are resulting in significant noncash ceiling test impairment charges in our oil and gas affiliate, NFR Energy. These amounted to 68 -- roughly $68 million this quarter or $0.16 per share. We expect the 12-month rolling average ceiling test methodology to impact subsequent quarters as well, of course, depending on where the gas price continues to go. These charges notwithstanding and as shown on Slide 8, we had a solid quarter operationally with operating income improving by $48 million, roughly 18%, sequentially; and $113 million, 54%, year-over-year. Seasonally strong first quarters in Alaska and Canada more than offset the customary seasonal weakness we usually see in our well-servicing and pressure pumping businesses. The majority of our businesses improved sequentially, the exceptions being pressure pumping, U.S. well-servicing and International, which were down but all better than expected. A few additional preliminary remarks before I get into the units. First, on taxes. Our reported effective tax rate from continuing operations for the first quarter was 32.5%, roughly. We anticipate our 2012 tax rate to be in the range of 32% to 34% for continuing operations. Even though we expect our International operations to grow, this segment will nevertheless be outweighed by the size of our North American operations, where the effective U.S. tax rate is around 38% to 40% and about 25% in Canada. I want to emphasize, however, that the majority of our worldwide tax expense is deferred. Furthermore, our cash taxes in the U.S. are minimal. We currently have a U.S. NOL that approximates $1.2 billion. These are all good characteristics for producing superior after-tax cash returns. Second, capital expenditures. Capital expenditures for the quarter totaled $470 million. Depreciation and amortization was $248 million. For the full year 2012, to give you some idea of where we think we're going to be, we think D&A is anticipated to be about $1.1 billion. We previously advised that we anticipated capital expenditures for 2012 to total about $1.5 billion. With the announcement today, which I'll get to, of the new rigs for Lower 48 land, we expect that number to be revised to be closer to $1.6 billion. We're also reflecting reductions in capital expenditures and other areas. That number may go down with further scrutiny and as the market evolves -- and I can assure you that one of the things that's very high on the plate is capital spending and making sure we're spending our money wisely, and that's under constant review. Third category, run rate. Slide 9 tries to put in context where we are on this journey. It provides a look at where our operating cash flow stands today compared to our prior high achieved in 2008. As you can see, our 2011 cash flow approximates 2008, while our first quarter annualized run rate is well ahead of that prior peak, even when adjusted downward to reflect first quarter seasonality in Alaska, Canada and rig services. Finally, some mention of asset quality and diversification. We have always recognized the cyclicality of this business. One way we try to mitigate risk and improve the value proposition for our customers is through long-term contracts, which provides the opportunity for constancy of work and serves our customers' interest as well. And I really want to emphasize it: I think the contracting strategy is a two-way street. There is substantial benefits to the operator as well as the service company. The other consistent theme in our strategy, over the many years, has been having a mix of premium asset classes and geographies that provide diversification and the opportunities to serve customers through multiple touch points. It is periods of stress, like we maybe see today, that show the benefits of our strategy. So let me now turn to the units, and for purposes of this discussion, we're going to break the units into 2 broad categories, like I previously mentioned: drilling and rig services, and then production and completion services. Starting with the drilling and rig services business line, if you turn to Slide 10, that shows that this group consists of our land drilling operations, offshore rigs, specialized rigs such as artic rigs, and other highly advanced rigs operating in remote locations. This group will also includes Canrig, our drilling equipment and rig operating software company, and our directional drilling operations. If you turn to Slide 10 (sic) [11], in the first quarter, this group posted $267 million in operating income, a 26% sequential increase over the fourth quarter. For interim reporting reasons, this includes about $6 million from our Canadian well-servicing operations. As I mentioned, that is on the list. We intend to look at monetizing that. The largest component of the increase came from our Alaska drilling unit, followed by rig services in Canada. Smaller but meaningful increases were achieved by our U.S. offshore operations and our US Lower 48 land drilling business, the latter of which contributed nearly half of the operating income of this group. If you turn to Slide 12, I think Slide 12 shows that our drilling fleet is really unique on the map. Slide 12 shows scheduled deliveries. The numbers on that slide show the -- not only existing, but rigs in the pipeline. We have 222 top-of-the-line A/C rigs, 6 of which are highly advanced offshore platform rigs and a number of highly advanced remote location drilling rigs working international and the artic. Additionally, we have 275 SCR rigs and 116 mechanical rigs spread throughout the world, which are all still highly utilized and viable in many markets. These rigs, with Canrig top drives and instrumentation, consistently match the performance of AC rigs and offer competitive day rates, both reasons why 31 of these rigs are working in the Bakken Shale today, where people do have choices of other rigs, yet these rigs with, in particular, mechanical rig with the K-box and AC equipment of Canrig, effectively competes against new AC rigs. Looking -- drilling down a little bit further on US Lower 48 land, our US Lower 48 land operation had reported operating income of $132 million, up from approximately $130 million in the prior quarter and up $52 million or 65% from the same quarter last year. In terms of activity, we added 2 rig years in the first quarter. Our average margins for the fleet rose slightly to $10,942 per day, with margins per day for AC rigs increasing $619 to $13,066, partially offset by $218 increase -- a decrease to $9,426 for our conventional fleet. The margin run rate for each class of rig is actually approximately $250 per day higher when adjusted for the higher payroll taxes you all know we typically incur in the first quarter. Leading edge day rates are generally stable everywhere during the quarter, except the Haynesville, where we're seeing them off by approximately 10%. As shown on Slide 13, our U.S. fleet is spread across every major unconventional and conventional oil and gas operating region and is complemented by a solid market position for our completion-of-production services. We are fortunate to be heavily weighted to the oil and liquids-rich areas of the Bakken and Eagle Ford shales. Our excellent operating reputation in these regions is why Nabors' rigs in Montana, North Dakota and Pennsylvania were recently visited by senior U.S. government officials, including the Secretary Salazar and U.S. senators and representatives from those states, which toured our AC rig operations. We tried to get them to change permit rules, but that didn't work. As we announced in our press release, we secured 9 term contracts with a major operator to furnish our newest generation AC rigs on -- all on 3-year terms. These rigs are expected to generate $280 million to $300 million in revenue over the term of the contracts, depending on the options selected. We also successfully packaged our Canrig technologies with the 9 newbuilds, which could contribute as much as $25 million more in revenue. Key features of these rigs include containerized modules which decrease rig mobilization time, multidirectional skimming capabilities for pad drilling, interchangeable components and engineered equipment that reduces nonproductive time. What we're on a quest to do is incorporate the best of what Nabors has, as a whole, to our customers, and we're having -- placing increasing focus on that directive. The $110 million of capital we expect to spend on these rigs in 2012 increases our total 2012 capital expenditure budget to $1.6 billion, as I mentioned. These rigs efficiently drill the extended laterals and challenging well programs our customers require. We are pleased to announce these orders, as it continues to reflect the market's acceptance of the value proposition of Nabors' new PACE rig design. With respect to leading edge rates, in the Rockies, Bakken and Northeast, to give you an idea of ranges, leading edge rates, we see mechanical in the range of $26 million; AC and SCR renewals, $26 million to $28.5 million. In the Mid-Continent and Gulf Coast, mechanical rigs in the Permian, 18,000 to 19,000; and AC and SCR rigs in the 23,000 to 25,000. And of course, with respect to newbuilds, depending on the options and what the configuration of equipment, that could be anywhere from 27,000 to 30,000. Our term backlog increased by a net 27 rigs during the quarter. As illustrated on Slide 14, 9 of these rigs were the aforementioned incremental newbuilds, while 22 were term extensions, 3 transitions from well-to-well to term and 11 new term contracts for existing rigs were offset partially by expiring term contracts that either went to well-to-well or were stacked. The extensions, conversions from well-to-well and new-term contracts for existing rigs were signed at rates about $500 per day higher on average than before. Our gas rig exposure has diminished somewhat from the 35 rigs we mentioned last quarter to approximately 30 today. Two gas rigs stacked and the others were repositioned to liquids markets. In the Haynesville, our exposure has decreased again from its high of 58 rigs to the 26 -- to 26 we mentioned last quarter to the 19 working there today. Of the 7 fewer rigs working there today, only 1's stacked, while the other 6 relocated: 4 to the Eagle Ford, 1 to the Permian and the other to the Mississippian. We currently have 220 rigs working today. Second quarter margins and rig count are expected to be roughly flat for Lower 48 drilling, with continued weakness in the dry gas market offset by our participation in liquid gas and oil-prone basins. We anticipate downward pressure on spot rates for the balance of 2012, but our outlook is bolstered by 2 factors: first, the 26 remaining new AC rigs that we will deploy under term contract commitments in 2012 and 2013; and second, the recent increases in our term contract backlog for existing rigs. I'd like to now turn to offshore. Our offshore operations reported operating income of $8 million, up from $3 million in the prior quarter and significantly up from the $4-million loss recorded in the first quarter of 2011. The margin improved as we are slowly putting rigs to work, as evidenced by that 2-rig-year increase we posted over last quarter and the 4-rig-year increase over the first quarter of last year. The Gulf of Mexico market is not improving as fast as we expected, as operators are continually restricted by ever-increasing governmental safety and environmental requirements. Permits can be prolonged by several months even for shallow water activity. Additionally, operators are becoming less and less active during hurricane season, again due to additional regulatory requirements. Our visibility is limited for the near term and is leading us to expect roughly 10 rig years for 2012. On a positive note, construction of the 2 new state-of-the-art 4,000-horsepower deepwater platform rigs is in full swing. These 2 rigs are the largest ever constructed for work in the Gulf of Mexico, and will further enhance our market-leading position in the deepwater platform arena. Alaska. Our Alaska drilling operation posted results of $27 million, up from $5 million in the prior quarter and $11 million in the first quarter of 2011. The increase is due to a busy winter exploration season with the majority of the work being frankly awarded to Nabors. We anticipate the usual seasonal downturn slowdown in activity in Alaska in the second quarter. However, there are a number of pending projects, both onshore and offshore, 2 on the North Slope and several in the Cook Inlet Basin, in which we are in a good position to participate. Additionally, if 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 generate projects that we're uniquely positioned to do, perhaps as early as the end of its year. This could generate additional opportunities for our proprietary North Slope coiled tubing drilling rig, which has been very successful. Canada. Our Canadian operations improved over the prior quarter due to the traditionally strong winter season. Including our Canadian well-servicing operation, operating income reached $49 million for the quarter versus $37 million in the fourth quarter. We averaged 49 rigs operating, a quarter-to-quarter improvement of 3.5 rigs. Despite an early spring breakup this year, average rig activity was only down one rig from the same quarter in the prior year. Margins increased to 14,281 per rig day, representing increases of about 2,200 and 2,280 over the fourth quarter and prior first year quarters, respectively. We expect results for the second quarter to be sharply lower with the early start to the spring thaw. We expect the strong start in the first quarter to yield improvement over the prior year, with drilling activity for the remainder of 2012 projected to be comparable to last year. As has been the case in the US Lower 48, reduced dry gas drilling is being offset by continuing demand from oil-directed activity and liquids-rich basins. International. Our International unit posted operating income of $21 million, down from $22 million in the fourth quarter of 2011 and $36 million in the first quarter of last year. This was higher than the anticipated, primarily due to additional rig utilization and the early startup of an offshore 2,000-horsepower newbuild in India. We still believe that this quarter represents the bottom for this operation. We expect this quarter represents the quarterly low and that the anticipated increase in the rig count to 130 rigs by year end will provide for a healthy improvement for 2012 and 2013. This confidence is supported by the startup of several high-margin, high-value projects over the next 2 quarters, which will offset the adverse effects of generally lower day rates, especially for our jack-ups, including rig 660, which recently received -- renewed through the year -- through the end of the year in Saudi. Rig services. Our rig services line consists of Canrig drilling equipment and software, along with our directional drilling operations and our Alaska oilfield hauling operations. This operation, as a whole, posted results of $30 million compared to $13 million in the prior quarter and $8.3 million in the first quarter of last year. Of the $17 million in sequential increase for this line, a large portion was attributable to Peak Alaska's seasonal high. The rest of the improvement was driven by our directional drilling operations in Canrig, which produced 37 top drives in the quarter, only 16 of which were for Nabors rigs. As Slide 16 shows, Canrig deployed 1,000th top drive in the field during the first quarter, a substantial achievement. It should also be noted that serial number 1 is still active in service. We specialize in long-tenure units in our company. Of this 1,000 top drives, about half are on Nabors rigs and the other half are on third-party rigs, including some deepwater offshore rigs. Additionally, Canrig is currently running 200 ROCKIT installations and 55 REVIT installations, proving that these advanced technologies are attractive to operators and enhance our value proposition. And that's further bolstered by this recent award, where the operator chose to add Canrig items to their package. Now turning to Completion and Production Services. I refer you to Slide 17. This group consists of the range of services we provide to complete and service the well throughout its lifetime. The division is further subdivided into 3 primary service lines: well-servicing, workover and coiled tubing rigs; fluids management; and pressure pumping operations. The operating results for this division is set forth in Slide 18. Completion and Production Services posted $87 million in operating income, down slightly from $101 million in the fourth quarter and up substantially from $55 million recorded in the first quarter of 2011. The sequentially lower results were better than expected as the seasonal effects were more moderate than normal. And now let's drill down to some of the components. Pressure pumping. Looking at the components in our pressure pumping business, the committed utilization under our 14 long-term contracts resulted in a new record for quarterly revenues and stage count, and at margins consistent with expectations. However, the spot market has deteriorated rapidly and the resulting lower utilization is creating unrecoverable costs for labor, fuel and transportation. As a result, overall margins declined by nearly 4% sequentially, with operating income of $65 million for the first quarter down from $76 million in the prior quarter and up from $44 million in the first quarter of 2011. Due to spot market conditions, we have chosen to idle 4 spot market spreads. These spreads were operating in the Marcellus, Haynesville, Granite Wash and Mid-Continent spot markets. In addition, we are delaying the deployment of our 25th U.S.-based large crew that we originally anticipated would commence operations in May. While we believe we have adequate supplies of sand, proppant and chemicals, during the quarter, we incurred temporary costs to relocate sand inventory, much like you've heard from other people. These amounted to approximately $3 million in charges. We have seen increased demand for 20/40 white sand in the oil-related activity and less demand for 40/70 and 100-mesh, and believe we have attracted -- attractive contracts for sand supply and pricing. Chemical costs increased sequentially, primarily driven by the much-discussed increased cost of guar, and we are continuing to develop guar supply alternatives. We have lowered our demurrage costs and we believe we have additional opportunities for further cost savings as we continue to expand our transload facilities to further integrate pressure pumping into Nabors' warehousing and transportation systems. We applied the contracting intellectual capital we developed in our U.S. land business to pressure pumping in creating the 14 long-term agreements. Referring to Slide 19, we currently have 10 crews working in the Bakken/Rockies, with 8 of these crews working under LTAs. 2 of our 3 Eagle Ford crews have LTAs. We have 2 LTAs in the Marcellus and 1 each in the Permian and Barnett. In total, over 70% of our expected 2012 pressure pumping operating cash flow is forecasted to be generated by those 14 LTAs. Additionally, we continue to cross-sell Nabors' multiple service lines to our LTA customers. While our visibility with respect to pressure pumping spot markets is challenged, given the current horsepower supply, demand and balance, we still expect this business to be -- post a respectable year given the 14 contracts we have in place and our overall position in the Bakken, Eagle Ford and Permian. Both in the Bakken and Eagle Ford, we have invested a lot in our infrastructure and we're continually working on lowering our costs. We've also put in facilities where we're consolidating multiple Nabors units in those facilities, which we think will leverage both the cost structure and also the touch points with our clients. And that's in place right now. Given our existing presence in these markets, we do not need to relocate crews to oily areas as do -- some other market participants had to do. There is less pricing pressure in our other business lines, and we see continued opportunities for growth, particularly in cementing and coiled tubing. We are intent on using our global scale and footprint to establish additional markets for our pressure pumping services. Over 2 spreads -- our 2 spreads on location in Canada will commence operations once the spring breakup ends, and we believe there are other emerging international opportunities for our pressure pumping services. Now let me turn to well servicing. Well servicing operating income of $22 million was down from $24 million in the fourth quarter, although this was less than we anticipated due to relatively benign winter weather. The lower results were primarily attributable to more than $3 million in negative sequential effects due to higher payroll taxes, workers comp and other accruals that characterize the start of a new year. Excluding these items, operating income increased on a sequential basis. Operationally, we saw a growth in each element of our business despite some degree of seasonality. Rig and truck hours increased sequentially by 5% and 3%, respectively, as we unstacked and relocated rigs from slower -- slowing gas markets to economically favorable oil and liquids-rich plays while expanding our truck and frac tank fleets. Average hourly rates also improved and we are up 3% sequentially for both our rigs and our fluid service trucking fleet. As shown on Slide 19, at the end of the first quarter, our U.S. operating fleet consisted of 567 well-service rigs, 957 fluid service trucks and almost 3,800 frac tanks. The second quarter and remainder of the year should exhibit further growth as we continued to expand to more robust markets, including the Bakken and Eagle Ford Shales and the Permian Basin and in 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. These positive effects will be dampened by reduced contributions from our Northeast operations due to the soft gas market. Longer term, we remain encouraged by the outlook for this primarily oil-driven business, as the large number of oil wells being added will convert to artificial lift systems over time and will require increasing frequent maintenance. In addition, the increased inventory of horizontal wells bodes well for this business with their higher workover intensity. We believe the industry's overhang of stacked service rigs that can be expeditiously and economically returned to service is dissipating, and this will eventually lead to improved supply-demand balances. Last item to talk about, oil and gas. As you know, as a result of our monetization efforts, our oil and gas segment now consists of only NFR, as all other holdings have been reclassified as discontinued operations. When we exclude the ceiling test impairment, our results were $5.7 million, up slightly from the $3.4 million reported in the fourth quarter. As you can see from the production reserve profile shown on Slide 20, while NFR's principal assets are East Texas gas, it has evolving prospects in 3 liquid plays. It has significant acreage that abuts and encompasses the liquids area Anadarko highlighted at their recent Analyst Meeting and another liquids play in the general area. It is also currently drilling on farming acreage in a highly prospective area of the Gonzales County section of the Eagle Ford play, slightly southeast of our GeoResources joint venture producing acreage. I think we have a very effective operating team in NFR, and I think it's a great platform for a company that wants to either enhance their position in the shales or for a new entrant. As I said, we look at all our options with respect to monetizing NFR. We have a very smart partner, First Reserve, that's aligned with us in terms of trying to seek value for our investment, and we hope to do the best we can in terms of unlocking some value. So in summary, Nabors remains in a good position even in the face of evolving macro uncertainty. This quarter's improvement in our more seasonally influenced businesses illustrates our potential to contribute meaningfully to our full year results. Our international business is poised for an upturn and we see long-term demand growth for the services provided by our U.S. land well-servicing operation. These factors, coupled with a degree of downside limitation provided by term contracts in our most favorable businesses, are the basis for expectations of a healthy 2012. With that, I'd like to turn it open to questions. Dennis A. Smith: Camille, I think we're ready to commence the question-and-answer session please.

[Operator Instructions] Our first question is from the line of Jim Crandell with Dahlman Rose & Co. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: My first question has to do with the asset divestiture program, and I guess it has 2 pieces. Number one, it seems to me that you might be backing off a little bit your decision to sell the International jack-ups. Does this reflect at all what you think you can get for those jack-ups in an environment where other companies are selling equipment? And my second question is, I wondered if you could just tell me your thinking about why sell Canada well-service rigs and keep U.S. And what were the considerations in that decision? Anthony G. Petrello: Sure, let me deal with the first one -- the second one first. The Canadian well-servicing marketplace, there's a number, it's not as -- whereas the U.S., there's a couple of big guys; in Canada, there's several big guys. And to get to a leadership position, I think we would have to grow that position, that's number one, and invest a bunch of capital. Number two, our position up there, unlike in the U.S., we don't have the fluids management trucking and other ancillary stuff that we have in the position down here. And then number three, in terms of just the way things seem to work up there, the amount of overlap between the 2 in terms of the synergies to be attracted, I just didn't see it -- us getting there as quickly. So those were all the motivations with respect to Canadian well-servicing. That -- I think it's a different position up there than here. With respect to the International jack-up, I remember reading your write-up and I don't think I've said actually anything different on the International jack-up than what I did last month. I think there's no question on the Gulf of Mexico jack-ups. The only issue with the International jack-ups, Jim, is some of our participation in that market has been at the insistence of some key NOCs, and we -- there's some relationships there and we just want to make sure that we do 2 things: that we're not taking a step backwards and that it just makes overall sense. And I think one of the good things is we're still operating ourselves to maximize that value and in particular, the fact that these things -- some of them have contracts right now, will be very attractive to someone else that wants to -- that is interested in the -- in those jack-ups. So we haven't shut the door on it. We're just being a little careful on it, and in terms of urgency, I'm not slowing down either. It just -- we're just being cautious. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. And just as a follow-up, one operational question, Tony. What do you think is the outlook now for new sort of 3- to 4-year contracts on fit-for-purpose rigs over the course of the year? What are your customers thinking now in terms of ordering more equipment? And have you seen any price competitiveness at all in that market? And is there any indication that, that 27,000 to 30,000 type day rate that you and some select others have been getting for that equipment might be under pressure? Anthony G. Petrello: Well, I'll let Joe answer some of these comments. But the first thing, I do think, as I said, that the appetite for certain people is not as great until people get a clearer view of their overall cash flow. The economics of the newbuilds, I still think, both in an operational and economic sense, will be liquid plays. And I think even in the medium term, that's going to drive the interest in them. In particular, [indiscernible] Texas as the plays move from vertical to horizontal drilling, the existing fleet of rigs out there, I think, is ill equipped to optimize that and I think there will be demand. I think the pace of the willingness of people to sign up, frankly, is going to be a function of what their position is, the commodity exposure on the gas and how much cash flow they have available and what other demands there are for that cash flow and whether it's free to invest. Now I think the fact that we just signed these contracts in this environment, I think, shows that people that have a program that they've committed capital to and have that horizon, that the newbuilds are still the way to go. And what we intend to do is add a bunch of stuff to it -- to those rigs to make that value proposition even more attractive, which is the reason why we're trying to extract more value out of Canrig. So, Joe, you have anything to add to that? Joe M. Hudson: Yes, Jim, again, the newbuild market is being driven by mainly the majors, large independents. A lot of them have strong asset positions. We think there's still the opportunity, specifically in our northern markets, which Tony spoke to earlier, specifically in the liquids area of the Bakken, that we think there's incremental opportunities there to move the rigs in. We do see some pressure from contractors who build rigs on specs, but those are drying up as announced on some of the previous calls. They're backing off. So as long as the operator wants a strong, premium asset to work in that area, then we think there's great opportunities for us.

And our next question is from the line of Jim Rollyson with Raymond James. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Tony, maybe just following up real quickly on Jim's last question. You mentioned earlier in your commentary about expecting kind of spot market land rates that may see some pressure throughout the course of the rest of the year. Is that strictly limited to the lower tier rigs? Or is that in certain markets on the newer class of rigs as well? Anthony G. Petrello: Well, so far the rigs that rolled over, actually, they rolled over -- the stuff that was on extensions rolled over basically at the levels they were at. And rigs that rolled existing newbuilds -- or AC-type rigs, I should say, existing AC rigs that rolled to different operators actually rolled at a higher margin than what they were at. So thus far, we haven't seen -- thus far, we've been in pretty good shape. Now as Joe mentioned, obviously, with the market, there is pressure, but in terms of what's happened so far, that's what happened so far. Clearly, when I talk about the downward pressure, I'm speaking of the -- I'm speaking of rigs that are in the gas areas, and we still have some of them. And as I mentioned, that is going down, so I am talking about those. And then, of course, now I have to be realistic. To the extent the commodity prices really tubes here and those rigs become available, I think there is a point at which everything gets affected. But that, I don't -- that -- we're not there yet. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Okay, that's very helpful. You guys put up really good numbers sequentially and frankly, for a long time in Alaska this quarter. I'm kind of curious, outside of the seasonal dip you'll normally have when you go into the second and third quarter, how is Alaska set up -- setting up as you go into next winter season? Are you going to get back to 8 rigs? Or is there upside of that number? We haven't seen 8 rigs in a while. Anthony G. Petrello: I'll let Denny talk. Dennis A. Smith: Yes, Jim, things are shaping up to be a pretty good exploration season next year as well. There's always some variability and risk in that, but -- and then we do have some prospects in other regions for this summer. And the big catalyst will be if, it may not happen this year yet, is the legislature tweaks the tax progressivity up there. Now that's really holding back a lot of capital spending in the legacy fields. And if that breaks loose, then we're almost in a position of being the marginal supplier. Anthony G. Petrello: Yes, the other thing I find, frankly, exciting is that the state definitely has an attitude now that they really want to encourage the independents or new entrants into the market, and they're spending a lot of effort. There were state representatives down here during a tour, meeting with all size companies, not just the large independents, but private companies. I think you all know about Hilcorp buying the position of Chevron up there. And so to the extent there are these new entrants into the market, I think it bodes well for incremental activity. And in fact, the way the tax scheme currently works up there, there's some great subsidies that people haven't really appreciated for new entrants. And I think that's now becoming better known and I think all that is -- creates at least the platform for maybe good things to happen. So with that pipeline only half full, it's a shame for having that resource not being drilled. So we're -- we have -- we -- long-term, I think it's a great position to be in that market. James M. Rollyson - Raymond James & Associates, Inc., Research Division: That's excellent. And the last question, just you mentioned the way things are setting up for at some point down the road in well-servicing in the Lower 48. You kind of see, maybe at some point, supply and demand coming together to where you maybe get some pricing leverage above and beyond the kind of "keeping up with cost" creep that you've had here in the last 12 or 18 months or so. Any venture of a guess of when that may happen? Is that a 2012 event, a 2013 event? Or kind of what are you thinking? Anthony G. Petrello: I'll probably just talk directionally. I mean, I think if -- to the extent you believe in the oil shale fee system and those types of wells, they are going to require these workover programs, and we've been at it for a while. And once we get on that cycle, once that cycle hits -- the stuff that's been going on in North Dakota, it's been going on for a while. But once that maintenance cycle starts, I think then, given the amount of drilling that's occurred, there should be a sort of regularized ongoing demand. And given the length of those horizontals and other aspects, it seems like most of the fleet that's out there may need some incremental investment to be in a position to handle that work, and I think that is pretty good. Whether that's beginning at 2013 or late 2013 or I -- I don't want to be guessing. I just -- but that's the way we see it.

And our next question is from the line of Jeff Tillery with Tudor, Pickering and Holt. Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Tony, it was just kind of other rig services in the Alaska business. I mean, Q1 such a big quarter and should come off hard seasonally. Could you just give us a feel for how you think about year-over-year growth for those businesses [indiscernible] this year? Anthony G. Petrello: Sure. I mean, I think we're already complicated and we already are producing lots of segment information, so there's a point at which -- we don't want to get into a position of giving everything out. But directionally, I know it's a really big number, and I think I said in my remarks a substantial portion came from Peak. The way that -- the other way to think about it is that the Canrig-Ryan component together had about a 25% increase. Okay? And frankly -- well, I'll leave it at that. Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: That's helpful. And for the -- as you think about the Alaska outlook for the rest of the year, I wouldn't expect to see the same type of year-over-year growth that you demonstrated in the first quarter. But do we see growth year-over-year in the subsequent quarters from Alaska? Dennis A. Smith: I think that subsequent quarters will be somewhat ahead of last year. But obviously, there's -- things go south pretty quick with the mid-April-type time when we get to get off the ice and get out of the exploration program. So second quarter will be down demonstrably in the Alaska businesses, but probably better than last year. Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then, Tony, you talked about the outlook for domestic rig count just industry-wide being flat to down as you go through the second half of the year. You guys have some contracted newbuilds coming into the fold. Do you think you'll be able to hold a stable rig count through the course of the rest of the year? Anthony G. Petrello: I -- well, that's our quest, but -- and thus far, on the rollovers, we've done a pretty effective job. And -- but as I said, there are challenges and I've tried to identify what the order -- what the principal challenges with those gas rigs that we have exposed and whether we could find homes and homes at acceptable prices will be the issue. But that's what we get paid to do.

Our next question is from the line of Kurt Hallead with RBC Capital Markets. Kurt Hallead - RBC Capital Markets, LLC, Research Division: Tony, I just -- you laid out your game plan for finding some alternatives for guar and then integrating pressure pumping into the rest of the well serve -- into the -- into your existing operations in warehousing and so on and so forth. So 2 things. I'm just wondering if you can give a little bit more color in terms of, when you talk about finding alternatives to your guar supply, can you provide a little bit more information on that? And then secondly, what are you targeting in terms of potential margin improvement or cost reduction from the integration of the pressure pumping ops? Anthony G. Petrello: Okay, let me speak to the second thing -- second item first. Obviously, both Superior and Nabors well-servicing have -- with the range of offices we have, they both have considerable overheads. We have not yet put a number on the consolidation, what the benefits are in terms of a cost consolidation, but we think it's going to be a decent number. On the issue of the guar, to be honest with you, I'm a little reluctant to tell you what we have up our sleeve. We are looking for is different country sources, as well as different alternatives as alternatives to the conventional guar. One thing that you have heard from other people that we are looking at is dry guar and mixing it as an alternative. But beyond that, unless, Dave, you're comfortable talking, that's something you can -- feel free. David E. Wallace: So, I think there's some chemistry options that we're looking at to take the place of linear gel. The cross-linked part gets a little more complicated. And as everybody's mentioned, guar is a big component of the frac-ing process, especially in the oil wells today. So we feel like we've got some stuff to help offset the linear and the cross-linked component. We're working on some stuff, but nothing to announce at this point. Kurt Hallead - RBC Capital Markets, LLC, Research Division: The follow-up is along the lines again on pressure pumping. I know we've heard from many different angles so we might as well just add another angle here. So what are you seeing in terms of the declines in spot market pricing? Do you anticipate that the pricing magnitude and hit will be felt primarily in the first half of the year? And then do you think it'll base out in -- around the third quarter? Can you give us some color along those lines? And then I know you have your -- I think you said 70% of your frac crews are on some sort of long-term contract. As those frac crews are rolling off them, I'm assuming you're going to roll off at lower margins, which would impact your margin compression into 2013. So I'm just wondering if you could give us some color on those items. Anthony G. Petrello: Sure. Dave? David E. Wallace: Yes, I think, Kurt, as you said, obviously the spot pricing is deteriorating, plus you have the utilization on top of that. Then again, that's one reason why we elected to stack out part of the crews at this point. We have a lot of -- we have a strong position with our LTSAs, and again, we're going to manage to ride those and take advantage of the position we have there. But we think the spot pricing's going to be a little choppy for a little while as the rig count kind of balances to where it needs to be. If we see more rigs going to horizontal, again, that's going to suck up a lot of the capacity. The oil areas, we have a really strong position there, so we're looking at the opportunities and deciding if it makes sense to shift resources there or let it stabilize a little bit. Anthony G. Petrello: Yes, and we're not afraid, as you've heard, to stack out if the -- if it becomes unprofitable, we're not afraid to stack out. And because we have a base of activity, whereas other people that are in a position where if they stack out, they may not have an operation left, we are not in that position. So with the existing contracts; with all the other things that Nabors does; and frankly, with the combination of putting the organizations together, we're actually going to be, I think, even in a stronger position. So that's part of the thinking about what we're doing in terms of organization. But we will not be afraid to stack out some stuff because the profitability on the existing contracts is quite attractive.

Our final question is from the line of John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Just a quick question on Slide 5. When you look at the shareholder equity numbers, $5.8 billion going to $6.7 billion for targeted, I just want to make sure that -- are you guys guiding $900 million of net income, the balance of the year? Dennis A. Smith: The net income, the $900 million... Anthony G. Petrello: Yes, well, part of that is the treatment of the $100 million [ph] [indiscernible] so there is an increased equity this quarter in addition to net income. Dennis A. Smith: John, part of that's a $100-million pickup from the reversal of the liability we booked in the fourth quarter. Anthony G. Petrello: Yes, the $100-million charge in the fourth quarter had to come back -- according to the accounting rules, had to come back through the equity statement, not through the P&L. So that's probably what you're seeing. John M. Daniel - Simmons & Company International, Research Division: Should we -- but should we view this as guidance from an earnings standpoint for the balance of the year? Anthony G. Petrello: No. John M. Daniel - Simmons & Company International, Research Division: Okay, I just want to make sure. Can you say how much of the -- and if you said this on the call, I apologize, but what the revenue contribution of the 4 idle frac fleets was in Q1? David E. Wallace: Yes, they were pretty minor, pretty low utilization and if anything, negative operating income. And again, that's why we elected to do that. Probably a small percentage. Dennis A. Smith: Thank you, John. And Camille, with that, we'll wind up the call. And we want to thank everybody for joining us today and look forward to talking to you next quarter.

Ladies and gentlemen, that does conclude the Nabors Industries First Quarter 2012 Earnings Conference Call. Thank you for your participation. You may now disconnect.