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Executives

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

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

Joe M. Hudson - President

Analysts

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

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Waqar Syed - Goldman Sachs Group Inc., Research Division

James D. Crandell - Dahlman Rose & Company, LLC, Research Division

Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division

Nabors Industries (NBR) Q2 2012 Earnings Call July 25, 2012 11:00 AM ET

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Nabors Industries Ltd. Second Quarter 2012 Earnings Conference Call. [Operator Instructions] This conference is being recorded today, July 25, 2012. I would now like to turn the conference over to Dennis Smith, Director of Corporate Development. Please go ahead, sir.

Dennis A. Smith

Thank you, Liz, and good morning, everyone. Thank you for joining us today on our second quarter earnings conference call. Our format today will be same as we customarily follow. We'll have Tony Petrello, our Chairman and CEO, provide you with our perspective on the quarter's results and give you some insight into how we see our business and markets evolving. In support of his remarks, we have posted some slides to our website, which you can access to follow along if you desire. They're accessible in 2 ways: First, if you're participating by webcast, they're available as a download within the webcast. Alternatively, you can download them from our website, nabors.com, under Investor Relations, then the submenu Events Calendar where you'll find them listed as supporting materials for this conference call. With us, in addition to Tony and myself today, are Laura Doerre, our General Counsel; Clark Wood, our Principal Accounting Officer; and all the heads of our various business units.

Since much of our remarks today will concern our expectations of future, they are subject to numerous risk factors as elaborated on in our 10-K and other filings. These comments constitute forward-looking statements within the meaning of the Securities Act of 1933. For such forward-looking statements are subject to certain risks and uncertainties as disclosed by Nabors from time to time in its filings with the Securities and Exchange Commission. As a result of these factors, we actually encourage you to look at those filings, and the results may materially differ from those that we think are going to develop.

Now I will turn the call over to Tony to begin.

Anthony G. Petrello

Good morning. Welcome to the conference call for the second quarter. I'd like to thank everyone for participating. As Dennis said, we do have the slides posted, and I will be referring to them by page number.

So before I get into the details, let me start with some macro comments, particularly those involving North America. First, let me say we would like to be cautiously optimistic about our overall outlook, but it is dependent upon a couple of factors that are not in our control or within our ability to predict, specifically commodity prices. The direction of domestic and global GDP, and there are problematic numbers out there that I'm sure you've all seen, will be a major determinant of these prices, along with the production decline rates and supply availability. Given overall demand uncertainty and several real-time indicators we will mention, it is more prudent and very cautious and conservative over the near term.

As you may recall in our fourth quarter earnings call last February, we expected a flattening to modestly declining U.S. land rig count in the second half, a moderation in the number of new build contract awards and the further deterioration of the spot market for pressure pumping. Many of those things have happened. This view was based on the lower gas -- natural gas price, leading to reduced customer cash flows and spending. In reality, the first quarter drop in gas prices caused an initial reaction that was largely offset by increased liquids-directed drilling. This gas-to-liquids offsetting continued throughout most of the second quarter. However, conditions became much worse towards the end of the second quarter as oil prices fell and the effects of declining NGL prices began to be felt.

As you can see on Slide 3, U.S. blended NGL prices are down 34% from the beginning of the year and 22% since April. This further erodes operators' cash flows and decreases drilling budgets. We see these same forces at work in Canada, but not yet as impactful.

The upper section of Slide 4 shows the Baker Hughes U.S. land rig count over recent cycles and, in the lower section, from its peak in mid-November to last week. Since the peak in November, we have seen a decline of 108 U.S. land rigs, 30 of which have occurred in just the last 2 weeks. This, coupled with recent customer conversations and competitive data points, support the lower end of our expectations.

Let me make clear, we do not yet foresee a sharp downturn but rather a moderate drop in rig count exacerbated by competitors offering uncontracted, newly built and existing rigs at lower rates and shorter terms in order to secure work. This is similar to the situation that played out earlier in the year with regard to Pressure Pumping, but we expect the extent of land rig oversupply to be much less.

We are also seeing operators farming out rigs they are committed to under term contracts. What this all translates into for us is the need to continue to focus on the matters we do and can control: our costs, our execution of work and improving our offerings. The situation internationally is more encouraging but subject to numerous other factors that influence the timing and extent of improvement.

Before I go into the details a few general points to cover as well. First, Nabors Well-Servicing Superior consolidation. As we previously highlighted, we have undertaken initiatives to streamline our business, achieve operational excellence and effect synergies and economies throughout our operations. The initial step is the consolidation of our well-servicing and pressure pumping businesses into one business line, Nabors Completion and Production Services, which is branded that way. Senior management for this organization has been set, and we are now implementing the reorganization at the field level, including consolidation of facilities. We are focusing on cost savings, which will become more visible in future quarters. The consolidation should also improve operational performance and, most importantly, broaden and deepen revenue opportunities with our customers.

Second, asset sale process. Another priority, as you know, has been balance sheet improvement to improve performance and monetization of noncore assets. The asset divestiture process is under way but moving slowly, more slowly than we had hoped. Nothing like selling stuff in this environment. However, we still expect to achieve our targets that we've set by this year.

The various assets we have designated for possible sales are listed on Slides 5 and 6. In Canada, we are in negotiations to sell our small Canadian aircraft business. Meanwhile, we decided not to proceed with the sale of our coil tubing business as the bids received were not acceptable. We continue to aggressively market these rigs and 2 of them were recently awarded winter work at good rates. We are currently evaluating the first stage bids of our Canadian well-service assets and expect to conclude a sale this year. However, as with the coil tubing rigs, we are prepared to continue with these assets on our portfolio should we not be able to arrive at an acceptable value.

We have initiated the sales process for our Peak Alaska subsidiary, and we expect the first round of bids in a few weeks. We hope to complete the sale in the fourth quarter as well. We also have a package and will soon launch marketing efforts for our jackups and barges.

On E&P front, I had hoped to report the third quarter sale of our Eagle Ford property since that is property in the fab [ph] part of today's market. However, the pending acquisition of our partner, GeoResources, has delayed the process a little. But the good news is, it confirms the estimated value of this holding. We still expect to conclude a sale by year end. The remaining E&P holdings, specifically Alaska, British Columbia and NFR, require more time to effect sales, as we previously said, but we will be pursuing them diligently and prudently to achieve value.

In Alaska, the limited number of current players in the North Slope market, along with the failure of the Alaska legislature to improve the onerous tax structure, is prolonging marketing efforts and will likely push any transaction into the first half of 2013. Nonetheless, these properties have real value and are strategically located within existing infrastructure, as shown on Slide 7, and consists of 3 different discoveries.

The value of our British Columbia properties is primarily a function of our Horn River basin holdings, which are shown on Slide #8. Our acreage is well positioned in the primary area of this play, and we will have more marketability once there is a more definitive time line for LNG exports. And of course, the recent transaction involving Nexen, where their property is pretty close there, should help as well.

The third: balance sheet, liquidity and strength. Our balance sheet remained strong. And as shown on Slide #9, we finished the quarter with $461 million in cash and investments. Our financial position is solid with leverage of 2.5x trailing 12-month EBITDA and interest coverage of more than 7.7x that amount. Except for our revolver balance of $910 million and $275 million in senior secured notes maturing in August, our term debt matures in 2018 or later. Total debt stands at about $4.7 billion, down $100 million from last quarter primarily due to the $70 million in proceeds we received from the sale of our remaining Colombian E&P interest. Our ability to reduce debt should increase significantly in the fourth quarter and throughout 2013 as capital expenditures wind down, notwithstanding lower expectations for operating cash flow in the near term. This marks the second consecutive quarter in which we generated more operating cash flow that we spent in CapEx, which reflects our commitment to contain capital spending and generate cash. We plan on utilizing our revolver in August to pay off the maturing notes.

Our net debt-to-cap is 42%. As you are aware, we have a target, which may seem ambitious in this market, of a reduction in net debt-to-cap from today's level of approximately 42% to 25% by the end of 2013. The chart on Slide 10 illustrates the impact of free cash flow generation on our capital structure based upon consensus EBITDA estimates and excluding any asset sales or additional capital projects. Since we first set that as a target and created the slide last fall, EBITDA estimates through next year have been reduced considerably, and we have increased capital spending by $175 million in light of the 9 rigs we were awarded last quarter that we announced. These changes have increased the estimated net debt to 30% achievable by the end of -- to 30% by the end of 2013, which implies it will take another 6 to 9 months, or approximately $680 million in asset sales, to reach our 25% target.

Now let me comment on the financial results. As we indicated in yesterday's press release and the prerelease the week before, we were disappointed that we did not meet our expectations this quarter. The shortfall in operating income was approximately $25 million primarily due to higher-than-expected costs of pressure pumping and international drilling. Operating income was $230 million, down from $321 million in the prior quarter, but up from $177 million in the same quarter last year. Seasonal effects in Canada and Alaska accounted for over $80 million of the sequential decline.

While our GAAP earnings per share from continuing operations was a loss of $0.34 per diluted share, it included $292 million in noncash charges, which amounts to $0.72 a share. More than half of these charges, approximately $146 million, were attributable to our share of an NFR ceiling test, with the balance attributable to 3 things: $75 million from the impairment of the Superior Well Services brand name, $26 million in goodwill impairments in our Gulf of Mexico and International operations and $46 million in asset retirements in Canada in our Completion and Production Services operation. When these charges are excluded, earnings per share for the quarter was $0.38 per diluted share.

Our effective tax rate for the quarter, excluding noncash charges, was 30.5%. We anticipate the full tax rate to be on the order of 31.5%.

Our capital expenditures for the quarter were $437 million with -- I mean, $437 million year-to-date and -- excuse me, $437 million for the quarter and year-to-date of $907 million. After we were awarded 9 new builds last quarter, we reported that anticipated capital expenditures would be about $1.6 billion for 2012. This has not yet changed. Depreciation for the year is expected to be about $1.1 billion. However, our businesses are closely scrutinizing our sustaining CapEx in the current market environment, and we are reviewing opportunities for further reductions.

Now let's turn to the performance of the operating groups. Drilling and Rig Services. As you know, this -- Drilling and Rig Services consists of our land drilling operations; offshore rigs; specialized rigs; drilling equipment and manufacturing; drilling software; and directional drilling operations. In the second quarter, this group earned $186 million in operating income, down $81 million from the first quarter of this year but up $32 million over the second quarter of last year. The largest component of the quarter-to-quarter decrease resulted from the predictable seasonality in the Alaska and Canadian markets, which were down $53 million and $19 million, respectively. Smaller but meaningful decreases came from our International operations and from our U.S. Lower 48 land drilling operations, which collectively brought this group down by $10 million. Our U.S. Lower 48 land drilling operations contribute nearly 70% of this group's operating income.

Slide 13 shows the current status of our unmatched worldwide drilling rig fleet. Including rigs scheduled to be deployed, we have 222 top-of-the-line AC rigs, including advanced deepwater platform rigs and remote location rigs in the Arctic and internationally. Additionally, we have 275 SCR rigs and 116 mechanical rigs, which still enjoy good utilization. A significant number of these rigs have been upgraded with Canrig top drives and instrumentation and consistently compete with AC rigs at comparable day rates in the most challenging basins. Including 12 new builds yet to be deployed, 171 of our rigs are outfitted with moving systems to accommodate pad drilling worldwide, which is increasingly becoming a differentiator as operators in the shale plays and others transition to manufacture and drilling.

Drilling deeper into this group, let's first look at Nabors U.S.A., the Lower 48. Our Lower U.S -- our U.S. Lower 48 land operation earned operating income of $127 million, down from $132 million in the prior quarter but up $27 million from the same quarter last year. In terms of activity, we lost 1 net rig year, but our average margins for the fleet rose by $239, finishing the quarter at $11,178 per rig per day. Margins for the AC rigs increased $328 per day, while margins for our legacy rigs decreased $227 per day. Margins for this business were effectively flat quarter-to-quarter after adjusting for the approximately $250 per day and higher payroll taxes we incurred in the first quarter. We deployed 11 new rigs during the quarter, bringing the total for this year to 18 new rigs deployed with another 12 contracted new rig deliveries scheduled through June of 2013.

As shown on Slide 14, our U.S. fleet is well positioned in every major oil and gas operating region and is complemented by the strong U.S. presence of our Completion and Production Service business. As of June 30, 130 of our U.S. rigs were drilling for oil, 41 for natural gas liquids, 36 for dry gas, and 3 for CO2. Once our schedule of new build deployments are completed, our U.S. Lower 48 fleet alone will have 92 of 171 rigs with moving systems designed specifically for pad drilling.

Beginning with the first quarter drop in gas prices, we saw contract renewal duration shrink from 18 to 24 months, down to 6 to 9 months. Now with the second quarter decline in both oil and NGL prices, operators are even more reluctant to sign contract extensions of meaningful length since both cash flow and drilling budgets are declining. Some operators have even begun cutting their drilling programs and subleasing their rigs to competitors even when it requires subsidizing the day rate. Our contract backlog at the end of the second quarter was 146 rigs, which was down 3 rigs from last quarter's second quarter backlog as a result of 3 lump sum early terminations. Overall, the contract backlog profile is essentially unchanged.

The declining industry demand for rigs brought on by softer commodity prices is exacerbated by the further relocation of rigs from gas into oily basins, the deployment of new rigs from our larger competitors and, increasingly, the deployment of new rigs from smaller, private, new market entrants. We estimate that over 100 new rigs have been deployed so far this year: about 60% by our 3 largest competitors and us; and the remainder by small, public competitors and private, new entrants. We expect another 100-plus new rigs to be deployed in the second half with the proportions flipped. Smaller contractor deployments have somewhat less of an impact on us since more than 70% of our revenue comes from customers that are large cap or bigger. These customers demand a higher standard of safety, quality and efficiency, which many small drillers have not shown an ability to provide.

In terms of basins, since April 1, we have seen a reduction in industry rig count in several basins with the greatest being 25 in the Eagle Ford, 20 in the Mid Continent region and 18 in the Northeast. The Bakken is now everyone's favorite place to seek oil, and the market there is seeing excess supply and price pressure. We also see operators' wall sizes affected by these forces. In general terms, across all markets, we are seeing declines from peak rates of about 10% for AC rigs and 15% for SCR and mechanical rigs.

Today, we have 204 rigs on revenue, including 3 not working but earning revenue. We anticipate the possibility of further declines in our rig count coupled with modest margin deterioration due to downward pressure on spot rates, which all should be partially offset by the remaining 13 rigs we will deploy at higher average margins during the next year on term contracts.

Now let me turn to U.S. Offshore. Our U.S. Offshore operation reported operating income of $10 million, up from $8 million in the prior quarter and significantly up from the $1 million loss recorded in the second quarter of last year. This increase was driven primarily by gradually improving activity as evidenced by a 2 rig year increase over the prior quarter. Margins were down almost $1,000 per rig per day during the second quarter due to a higher proportion of smaller rigs operating. We expect this business to be significantly dampened throughout the third and early fourth quarters as many of our customers suspend operations during hurricane season, which is usually mandated in today's regulatory environment. However, we are encouraged by the degree of planned work for the fourth quarter, supported by the fact that our customers have placed 4 of our platform rigs on reduced standby rates for work planned to commend to -- planned to commence in November. We are also encouraged by the price increases in jackup rates where leading-edge rates are on the order of $50,000 to $55,000 per day for our shallow water workover rigs compared to $38,000 to $42,000 per day in December of last year.

Construction of the 2 new 4,000-horsepower deepwater platform rigs we are building for major customers is progressing on schedule with deployment anticipated in the first half of 2013. One rig is being sold to one customer, which we will operate and we are receiving progress payments during construction. As we have previously noted, these 2 rigs are the largest platform rigs ever constructed for work in the Gulf of Mexico and further demonstrate our ability to provide innovative, state-of-the-art rigs for the most challenging applications in the world.

Alaska. Our Alaska drilling operation posted an operating income of $9 million, down from $27 million in the seasonally strong first quarter, but up slightly from the $8 million posted in the second quarter of last year. Cook Inlet activity is improving as some large independents have recently become active in the market. The 2013 North Slope exploration season in Alaska is expected to be strong as new entrants are taking advantage of exploration credits and securing multiple rigs. The state legislature failed to reduce the oil tax progressivity, which is continuing to limit capital spending on development drilling in the North Slope legacy fields. However, assuming revisions in the tax structure, there are a number of significant projects planned for which Nabors is well positioned given our on-the-ground asset base, technological capabilities, operational excellence and proven ability to deliver on time and on budget in that difficult market.

Let's turn to Canada. Our Canadian operations sustained a loss of $4 million during the quarter. A very wet and rainy June extended the spring thaw and inhibited the resumption of activity for both drilling and well-servicing rigs. This adverse weather, along with further shrinkage of activity in gassy areas, led to a year-over-year decline of roughly $1,700 per day per rig in margin and 2.2 rig years in activity.

In our drilling operations, we recently completed the fully rigged up, pad-to-pad move of over 1 mile using our Rig 103. This rig uses a unique moving system we refer to as a table top system where we can move an entire conventional rig in one piece on a walking beam system. The operator concluded it was faster and more cost effective to build a road and utilize our state-of-the-art walking system rather than rigging down. Photos of this rig moving down the road are at the end of the presentation. That's kind of interesting to look at.

Pad drilling is also becoming more common in Canada, and we are well positioned in this area with 17 rigs with moving systems, and that's the strength that we continue to want to focus on in that market.

The outlook for the second half of the year in this market has recently moderated. Much like in the U.S. Lower 48, this market is seeing an aggressive number of new rigs relative to its size. We estimate 30 new builds have been deployed into this market in the first half of the year and expect another 18 to deploy in the second half. However, net-net, we expect our results to be in line with those we achieved last year.

International. International's failure to climb out of the trough was a disappointment. This business earned operating income of $16 million, down from $21 million last quarter and $36 million in the same quarter last year. The miss was caused by roughly $5 million in higher-than-expected labor and R&M expenses and $7 million in higher depreciation expenses. The labor portion of these costs was in the form of mandated wage increases for much of the local workforce in Middle Eastern countries, which we hope to recover at some point. Bulk orders of spare parts from remote operations and a delay in the start-up of 2 significant rigs, 1 a high-margin jackup in the Middle East and the other a high-margin land rig in the Far East, also contributed. Increased depreciation associated with new and upgraded rigs, which have not yet meaningfully contributed due to start-up costs, had a further negative impact on results in this business.

Despite not being reflected in the numbers, there were, however, some positives in this business during the quarter: the start-up of a 3,000-horsepower platform rig in India; the departure from dry dock of the last of our 4 Saudi jackups, and that last one is now on location and should go on payroll shortly; and the deployment of the final land rig of our Saudi ramp-up, bringing the current rig count there to 32 in that market. It's been a difficult process, but we're hopefully at the end of actually getting them all on the payroll.

Going forward, we are targeting improvement throughout the second half of the year and into 2013, especially with these recent rig deployments and the expected start-up of our highly advanced land rigs in Papua New Guinea.

There is visibility for increased tender activity in several markets. However, a large portion of International -- of our International revenue base is comprised of national oil companies. NOCs are also not immune from commodity prices as their oil revenues must also serve the needs of their host governments. The 10-rig tender in Algeria that was canceled -- that we had won 8 of those rigs but that was subsequently canceled, is a good example, as are -- and there are similar examples in Iraq and in Venezuela. We also have several rigs which recently commenced new contracts that will shut down at a future time convenient to our customer for upgrades. The overall result is an environment of delay, cost creep and unpredictability in the international marketplace, which creates some hurdles. These, I want to say, are not excuses. It is our job to mitigate these negatives and exploit the unequaled international drilling footprint Nabors currently enjoys. We see potential in the near term for putting platform and land rigs to work in several markets, and we're doing our best to deal with all the challenges I just mentioned.

Rig Services. Our rig service line, which includes Canrig, Peak and Ryan, posted results of $28 million this quarter compared to $30 million in the prior quarter and $14 million in the same quarter of last year. Over 70% of these results were contributed by Canrig, which delivered a record number of top drives and still expects to contribute over $100 million in EBITDA this year through higher capital equipment deliveries. During the quarter, Canrig delivered 42 top drives, almost half to third parties, which is an all-time quarterly record. Canrig is strong in the Russian market where we expect to deploy over 15 capital units this year, bringing the total to over 100 units delivered there since 2003. We expect to deploy our first nonstop driller package in the third quarter, a more efficient system which allows continuous circulation while making connections.

Approximately $4 million of the operating income came from Peak, which last year had a loss in the same period. The year-over-year improvement is mainly due to supporting an active shale exploration program and maintenance and expansion projects on the North Slope. This business is expecting an improved summer in Kenai and another busy winter exploration season. As you know, we are currently marketing this business for sale. We have received a great deal of interest from potential buyers, and we hope to have a sale completed by the end of the year.

Now let's turn to Completion and Production Services. This group consists of the range of services we provide to complete and service the well throughout its lifetime. The business line consists of various services that complete and maintain wells, including well-servicing, workover and coil tubing rigs, fluid managing and pressure pumping operations. Operating income for this division is tabled out on Slide 17.

Completion and Production Services posted $75 million in operating income, down from $87 million in the first quarter but up substantially from the $60 million recorded in the second quarter of 2011. The sequentially lower results were worse than expected due to weak pressure pumping performance, partially offset by better-than-expected well-servicing results.

Drilling down on the Pressure Pumping, we now have 26 frac spreads in the United States and Canada with a total hydraulic horsepower of 805,000. In the U.S., we have 13 long-term contracted crews, which have maintained fairly high utilization levels. However, some long-term customers have reduced stage counts to contractually required minimums. The spot market has continued to deteriorate, and the resulting lower utilization is creating unrecoverable costs for labor, fuel and transportation. Lower utilization, combined with higher material costs, caused overall margins to decline by 4% sequentially. Operating income of $46 million for the second quarter was down from $65 million in the prior quarter, but up slightly from $44 million in the second quarter of 2011. This quarter's operating income included about a $2 million loss for start-up operations in Canada.

Regarding our material costs, we believe our guar gel costs peaked in July, and we expect these higher prices to be reflected in the third quarter. However, guar prices should soon decline from recent highs as the market returns to historical supply-demand balance. We now average roughly a 45- to 50-day supply of guar, which means costs should work their way through the supply chain by the early fourth quarter. Meanwhile, we are also continuing to develop our own guar substitutes.

With the continued weak spot market conditions, in June we idled an additional crew. In the U.S., we now have 5 spot market spreads idle. These spreads were operating in the Marcellus, Haynesville, Granite Wash, Mid Continent and Barnett markets.

Referring to Slide 18, we now have 19 crews working in the U.S. and 2 in Canada. We have 10 crews working in the Bakken/Rockies, with 8 of the crews working under LTSAs. Two of our 3 Eagle Ford crews have LTSAs. We have 2 LTSA crews and 1 spot crew in the Marcellus, and 1 LTSA crew and 2 spots in the Permian. Two crews are now on the payroll in Canada, having started this month.

Our visibility with respect to the near-term pressure pumping spot market remains challenged given the current horsepower supply-demand imbalance. We will continue to proactively manage our spot crew exposure, being careful not to run rigs at too low yields -- spot crews at too low a utilization because it just eats up costs. And at the same time, with the consolidation of our well-servicing and Pressure Pumping operations, we are focused on expanding our service offerings as well as minimizing the cost of that operation. We also intend on using our scale and footprint to establish additional markets for the Pressure Pumping services, including selected international markets.

U.S. Well-servicing. The well-servicing operating income of $29 million was up from $22 million in the first quarter and $17 million in the second quarter of 2011. We saw sequential growth in each element of our business. Both rig and truck hours increased 3% as we relocated equipment from the weaker Northeast markets to West Texas, East Texas and the Bakken while expanding our trucking and frac tank fleets. Average hourly rates were up 2% sequentially for rigs while being down 10% for our fluid services trucking fleet due to relocating 46 trucks and 6 rigs from the Northeast market where rates are higher. Increased volumes and hourly rig rates more than offset the decline in truck hourly rates. The sequential improvement also reflected a $3 million reduction in direct and SG&A costs and the absence of $3 million in payroll taxes, workers' comp and other accruals that routinely affect the first quarter.

As shown on Slide 18, at the end of the second quarter, our U.S. operating fleet consisted of 467 well-servicing rigs, 1,020 fluid service trucks and about 3,800 frac tanks. The second half of the year should show moderate growth as we continue to expand into more robust markets, including the Bakken and the Eagle Ford shales, the Permian and California. We are converting Bakken daylight rigs to 24-hour rigs and lowering our transportation costs by utilizing our own relocated equipment to move our workover rigs. We are encouraged by the long-term prospects for these services given the large number of new oil wells which will convert to artificial lift systems over time and will require increasingly frequent maintenance. The increased inventory of horizontal wells, which are more workover intensive, should also increase the demand for these services. The industry's overhang of stack service rigs that can be expeditiously and economically returned to service is dissipating, and this reduction will eventually lead to improved supply-demand balance and improved margins.

One final comment, Oil and Gas. Our Oil and Gas segment now consists solely of NFR as all our other holdings have been reclassified as discontinued operations. When we exclude the ceiling test impairments, our results were $5.1 million, down slightly from $5.7 million reported in the first quarter. As I mentioned previously on calls, the NFR website has a lot of information about their activities and operations for those interested. The NFR's principal assets are East Texas gas, but it has an evolving prospect in 2 East Texas liquid plays: one that abuts and encompasses Anadarko's acreage and another in the same general area. It also currently is drilling on a farming acreage in a highly prospective area of the Gonzales County section of the Eagle Ford, slightly southeast of our GeoResources joint venture producing acreage. Again, we will look for any opportunity to extract value from our position with NFR, and we have a very good partner to help us do that.

In summary, in this type of market uncertainty, our strategy of maintaining a portfolio of diverse, premium assets in multiple market segments has served us well. I think we have the talent, the resources and the commitment to address the challenges this market presents, and we will use every opportunity to improve our company for the long term. Thank you for your attention and your patience, and we'll now take your questions.

Dennis A. Smith

Operator, we're ready for the Q&A section of the call, please.

Question-and-Answer Session

Operator

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

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

Tony, it sounds like on the International front that opportunity is still around. You're still seeing interest levels and bidding for different parts of the world on rig activity, and it seems like the big challenge you've had is just kind of delays in one shape or another from -- really driven by customers, it sounds like. And so I appreciate the fact that visibility is a little bit challenging. But curious what you think, with what you know today, maybe what your exit rate looks like for the International rig fleet at the end of the year?

Anthony G. Petrello

Yes, I think it's -- the exit count at end of the year is like 127 to 130 rigs, at that order of magnitude.

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

Okay, which I think last quarter, you were right around 130 was the expectation. So that still hasn't necessarily changed, just the timing of when this flows in through the rest of the year?

Anthony G. Petrello

Correct.

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

And on the domestic side, you gave pretty good color, I think, on the rig side of the business, just some of the softness you've seen in leading-edge rates and terms shrinking down a bit. On the contract kind of cancellations or buyouts, have you started seeing much of those? It looks like from the slides that you've got an uptick in expected payments on contracts going over $8 million. I'm curious if you're starting to see customers want to try and buy out more rigs? We've seen that in a couple of other guys so far. I'm curious what you're seeing there?

Anthony G. Petrello

Well, we've had 3, but I'll have Joe comment.

Joe M. Hudson

Yes, the answer is we are seeing customers looking to buy out some contracts. So yes, the answer is to date, we had maybe 6 through the process that if they're not buying the contract out, the rigs were actually -- as Tony mentioned, there's 3 rigs right now on payments through the month, which is what the contract allows for.

Anthony G. Petrello

Yes. And one of the things I think where you'd -- given our portfolio of assets we're able to do is also try to work with customers to make it less painful and, in the long term, make it a win-win. So we have a lot of other services that we could give people. And one of the benefits of doing stuff with Nabors is the fact that we have a full range of other things to offer. So we're always looking to -- on the one hand, we want to get the value for what we have invested in and received in terms of contract commitments. But on the other hand, we want to make sure we're providing value to the customer and helping him through his problems. And it's our job to sort of manage that balance.

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

Sure. And Joe, are you finding it possible to recontract those rigs elsewhere when you get buyouts? Or is the market just a little too squishy right now?

Joe M. Hudson

No, we've been able to secure some work with some of the rigs that are specifically on the lump sum terms that are paid out. And in some cases, we've been able to redeploy those rigs. In some cases, we're -- we've got some commitments, but it's not near term. It may be 30, 45 days down the road that they want to pick up the assets, but, yes, that is an option. As Tony mentioned recently, we've had the opportunity with a major operator that -- he chose to redeploy that term to Canada in lieu of the term in the U.S. So it's a great opportunity for our Canadian guys to have the contract structured in the U.S. I guess we used to call it metric days and now have been redeployed to the Canadian market.

Operator

And our next question comes from the line of Jeff Tillery with Tudor, Pickering & Holt.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

In the slides, Tony, one of the titles was kind of U.S. Rig Count - At An Inflection Point? And I'm just curious if you can talk, either basin or regionally, where you think Nabors will show or is showing the more significant utilization weakness. And now I'm sure it's going to be a -- kind of compound of both your contracted and uncontracted exposure as well as what the customers are doing, but just curious where you're seeing the utilization weakness?

Anthony G. Petrello

Sure. Joe, you guys got the...

Unknown Executive

In what regions are you seeing the weaker markets right now in utilization in particular? The industry and us?

Joe M. Hudson

The critical area for us right now is we're seeing -- I mean, there are still, although it's moderated, as Tony comments said and he's tested [ph] the Haynesville, that's actually the strengthening of the gas market, that's abated. The Eagle Ford, we're seeing some weakness there, and that's mainly along the lines, as you mentioned, on the natural gas liquids. So there's areas across the U.S. and then the rigs that continue to flow into the Bakken, although that is our strongest area, that is being impacted commercially by all of the offers from other companies. But converse to that, there are areas that we find in Central Texas, some areas that we're seeing some improvement. And that's what -- as Tony mentioned, we can't give them excuses. We've got to find places to redeploy the assets, and that's what we've done.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then for the Pressure Pumping business, half the spreads on contract. I guess, could you -- 2 questions along those lines. Are the spot fleets profitable from an EBIT standpoint at this point? And then could you just give us some color on when some of the contracts start to roll and additional spreads hit the spot market?

Anthony G. Petrello

Ronnie [ph]?

Unknown Executive

Yes, I think that as far as the pricing in the spot market we're still seeing pressure, albeit maybe not as much in some of the dry gas markets. But as we start to see rebalancing of assets, we are continuing to see some pressure in the liquid-rich areas. What was the second part of the question?

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

It's really...

Unknown Executive

Yes, yes, a little color on the contracts. Outside of 1 LTSA that will expire at the end of this year. The rest will expire at various points in 2013 with the number going into 2014 as well.

Jeff Tillery - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then those spot spreads, are those still profitable for you guys at this point? Or is there -- I'm sure they're cash flow positive, but are they actually generating EBIT?

Unknown Executive

Yes, they are.

Dennis A. Smith

It's dependent upon utilization, Jeff. It -- you don't need to lose much utilization to ...

Unknown Executive

Utilization has got to be there but the pricing as it is right now does make it profitable, correct.

Operator

And our next question comes from the line of Waqar Syed with Goldman Sachs.

Waqar Syed - Goldman Sachs Group Inc., Research Division

My question relates to one -- in the Middle East, the labor escalation that you saw. Is that a onetime? Or do you think this is going to be a recurring cost, that $5 million cost?

Anthony G. Petrello

Well, that was a -- it was -- those costs were sort of dictated very centrally, and I think it was in response to sort of macro issues going on in the region where the government sort of said local people had to get paid a lot more because there's a different agenda being served. So that's why they were unusual and that created the dilemma for us, that we sort of had -- we sort of were forced to do it just because it was sort of mandated. So hopefully, that is not -- those kind of mandates don't occur all the time. And we are trying to do our best to see what portions of those could be recovered.

Waqar Syed - Goldman Sachs Group Inc., Research Division

Now what I want to understand is was that a onetime bonus? Or is that just the salaries have been increased, every year you have to pay an extra $5 million?

Anthony G. Petrello

It was salary increases.

Waqar Syed - Goldman Sachs Group Inc., Research Division

Oh, that was a salary increase.

Unknown Executive

Actually it was both. It was both. In some cases, it was salary increase; in some, that was onetime deal. So it was both depending on the country where we're in.

Waqar Syed - Goldman Sachs Group Inc., Research Division

Okay. And secondly, as I look at your chart for the rig count decline that you mentioned, about 108 rigs or so since the peak, the same data shows on Baker Hughes that actually, the horizontal rig count went up by about 7 or 8 rigs during this time period and all the fall was just on the vertical rig side. So is that consistent in what you're seeing as well, maybe more pressure on the lower end? And you mentioned some on the day rates side, but what are you seeing in terms of, like, activity with just the vertical rig count, which may be -- sometimes there's some seasonality attached to that as well overall?

Anthony G. Petrello

Yes, I think vis a vis, yes, I think you're absolutely right. There is a distinction, a dichotomy between the horizontal and the vertical. And I think the horizontal in some sense is a better metric for us in terms of where our utilization is going because it's really in those kind of plays, that's the market for our asset base. And it's also -- the horizontal rigs are working and those things that make economic sense in terms of the plays that are active, so I think you're right. Looking at the overall curve may not necessarily reflect -- for those people active in this particular segment, may not correlate as well as looking at what the horizontal is, which also in part is the reason for our saying we don't see a steep drop-off, a -- possibly a moderate drop-off for exactly that reason you've identified.

Waqar Syed - Goldman Sachs Group Inc., Research Division

And secondly just recently in the last couple of weeks, you've seen a change in NGL prices as well, and some of the turnarounds in terms of the uses of the NGL. The prices have picked up, gas price have picked up. Oil is back around $90. Are you -- your pessimism, is that based on discussions over the last 1 or 2 weeks? Or is that based on more like what was happening a month ago or so?

Anthony G. Petrello

Well, when you say pessimism, I think that what I've tried to say is that it's almost a tautology between pessimism and optimism versus what your view is as to what the commodity price is. If the commodity price is going to be $85 and above and $3 gas or so, then to me that -- it's almost tautologically reason to be not pessimistic, but cautiously optimistic. And so -- but if you have the view that -- of the reverse, then there's reason for concern. And -- but you guys are as good, if not better, about figuring out what that -- what -- where those price curves are going. And so that's the way we look at it. Since we can't predict with certainty either one, we're just managing ourselves to handle the things that we can control.

Operator

And our next question comes from the line of Jim Crandell with Dahlman Rose.

James D. Crandell - Dahlman Rose & Company, LLC, Research Division

Tony, in the land rig business, a lot of your strategy for differentiation has been through introducing products like ROCKIT and REVIT into your own fleet and that's met with quite a bit of success. In a more difficult or more challenging market, does that -- do you think it -- does that slow down the acceptance or the penetration of ROCKIT and REVIT? Or is it just as desired on the part of the operator as it is even in hotter markets?

Anthony G. Petrello

I think it's -- number one, I think it ought to be as desired. And number two, I think in a market that's more difficult, it ought to be even more desirable because I think the value proposition is greater. And our marketing effort to push those is -- we're putting even a greater emphasis on it. And interestingly, we actually have some requests from operators that don't even have Nabors rigs, interested in some of those products. So I think it's -- the way the market is today, operators care about value and cost per well, and those products help them get there. So...

James D. Crandell - Dahlman Rose & Company, LLC, Research Division

And would you sell ROCKIT to those operators on some -- let them put it on somebody else's rigs?

Anthony G. Petrello

Well, we -- operators that have -- I guess the answer is we always think our stuff works better on Nabors rigs because we have Nabors people and we know how to operate the stuff. So that's the short answer. There is some Canrig equipment on some operator-owned rigs. And so on some operator-owned rigs, we have, in certain cases, let -- given some access to the equipment. But our primary focus right now is for our current customers using Nabors rigs to make sure they really are aware of the products, and they're using them to their fullest extent.

James D. Crandell - Dahlman Rose & Company, LLC, Research Division

Okay. Second question, Tony, I guess you've been CEO about 9 months now and aside from asset sales and balance sheet progress, how do you think you're progressing on your other initiatives that you've laid out over the last 9 months or so? And in general, is it easier or harder to effect change than you would have thought going in?

Anthony G. Petrello

I'll answer the second one first. It reminds me of International. It always takes longer than what you otherwise thought. And it's -- so from a timing point of view, I don't find it an issue of being easy versus hard. I think the people, the workforce we have here is really committed to taking Nabors to another level, and I have a lot of support from a lot of people here to do that. And so -- but we are a large company, and we've done certain things the way we've done historically for a long time. And for example, put driving through this new matrix concept through the company is a lot of work, and it's not something that we're going to get done in a couple of quarters. But we're making a lot of progress on it. And we've brought in some senior people in the functional areas, and we've brought in some other people in the operating areas in each of the business units and people are delivering on that. And at the same time, one of the visible things is the consolidation of Nabors Well Services and Sweezey, but we're looking at a whole bunch of initiatives through the company to similarly drive a more efficient company. So it's not just supply chain and facility consolidation, asset utilization, continued back-office improvements; there's a whole series of things. And -- but it's -- as you've signaled, it does take a bit of time.

James D. Crandell - Dahlman Rose & Company, LLC, Research Division

Okay, good. And then last question is just a quick one. And Joe mentioned the Haynesville a little while ago. And then Joe, maybe we can get your opinion based on the operators you talk to down there. What kind of a gas price does it take to really get the Haynesville going again?

Joe M. Hudson

Well, I haven't heard specific numbers. We -- the -- a majority of the operators working for there already have large position acreage. And so that's truly what's been driving that rig count. We -- they're trying not just to maintain a quick [indiscernible] and develop acreage, especially companies that come in from outside the U.S. to buy the properties, and they've got to show production, it's got to show something back for the investment. So one of the areas we're seeing is the northern extension of kind of the Eagle Ford up into Central Texas. That's where we've seen a lot of success. So East Texas taking off to go to the Eagle Ford and to West Texas, different areas, I think that's going to mitigate [ph] considerably.

Anthony G. Petrello

Yes, the way I would answer that question, Jim, is if you look at NFR, if -- at a $4.50 gas price, their economics start to look really different. So -- okay, so.

James D. Crandell - Dahlman Rose & Company, LLC, Research Division

Okay, good.

Anthony G. Petrello

That's one way of looking at it, so.

Operator

And our last question comes from the line of Scott Gruber with Bernstein.

Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division

I had a question on the operators' appetite to continue to support the build-out of AC-powered rigs. You look at the horizontal rig count in the U.S., close to 1,200, still well above the number of AC rigs that are operating even if the active rig count bleeds some. Tony mentioned rigs being down for the AC rigs a little bit. But what's your gut telling you today in terms of whether that falls below the reinvestment threshold or whether those rigs can hold up, and whether the appetite's changing given the shift toward more pad drilling and away from just drilling the whole acreage by production?

Anthony G. Petrello

Yes, I think for all the reasons we've spoken about today, let's not confuse a pause with sort of the long-term business here. And I think on medium- and long-term business, for those people that have invested in the shales, the fit-for-purpose manufactured drilling concept is core to realizing value. And so I think for those operators that have significant programs that will require development drilling over many years, they will continue to be interested in and will, in fact, want to be part of a process to look at the next generation of fit-for-purpose rigs. And that will occasion doing that on a long-term basis, I think that's what's going to be required. And that's what's going to be required to drive the efficiency and maximum value to the customer. So just because there is a breather here because of the shifts and uncertainty as to where -- what kind of environment we're in, I still think that the overall game hasn't changed.

Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division

And how do you think about the spread between the SCR rigs and the AC? What type of maximum spread would be just too wide for an operator to tolerate such that they do trade down and pick up an SCR rig rather than funding a new build?

Anthony G. Petrello

Well, I mean, the first thing is that our SCR rigs -- a lot of our SCR rigs, as I mentioned, have already been refurbished with a -- what's called a K-box, which is a Canrig tool. And when you put this on a rig, it basically gives that rig the functionality of an AC rig. And so that -- the whole point of that is to narrow that performance gap and, of course, from our point of view, the day rate gap. But depending on area, in some areas for those kinds of rigs, there isn't much of a gap. But in other areas, the gap could be anywhere from 5% to 10% delta on the day rates.

Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division

And is that kind of where you think the spread will stay? Or do you think it can widen some?

Anthony G. Petrello

Over time, I think it will widen.

Dennis A. Smith

Operator, that concludes our question and answer. If you want to close the call out, please?

Operator

Thank you. Ladies and gentlemen, this concludes the Nabors Industries Ltd. Second Quarter 2012 Earnings Conference Call. This conference will be available for replay. If you -- you may access the replay system at any time by dialing 1 (877) 870-5176 or 1 (858) 384-5517. Thank you for your participation. You may now disconnect.

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