Nabors Industries Ltd (NBR) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Nabors Industries Limited second-quarter 2012 earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions.

(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.

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 the same as we customarily follow. We will 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 are accessible in two ways. First, if you're participating by webcast, they are 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 the numerous risk factors as elaborated upon 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 that 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 our results may materially from those that we think are going to develop. Now we will turn the call over to Tony to begin.

Good morning, welcome to the conference call for the second quarter, and I would like to thank everyone for participating. At Denny said, we do have these slides posted, and I will be referring to them by page number. Before I get into 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 am 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 to be 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 US 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 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 begin to be felt. As you can see on slide 3, US 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 the same forces at work in Canada, but not yet as impactful.

The upper section of slide 4 shows the Baker Hughes US land rig count for 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 US land rigs, 30 of which have occurred in just the last two 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 foresee a sharp downturn, but rather a moderate drop in rig count, exacerbated by competitors' offering uncontracted, newly built in existing rates 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 duly 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 validation. As we've previously highlighted, we have undertaken initiatives to streamline our business, achieve operational excellence, and effect synergies in 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 non-core assets. The asset divestiture process is underway but moving more slowly than we had hoped. Nothing like selling stuff in this environment. However, we still expect to achieve our targets that we have 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 two 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 in 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 the E&P front, I had hoped to report the third-quarter sale of our Eagle Ford properties, that is property [in the fact 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 holdings. 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've 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 consist of three different discoveries. The value of our British Columbia properties is primarily a function of our Horn River Basin holdings, which are shown on slide number 8. Our acreage is well-positioned in the primary of this play, and we will have more marketability once there is more definitive timeline for LNG exports, and of course, the recent transaction involving [Nexon], where property is pretty close there, should help as well.

The third, balance sheet liquidity and strength. Our balance sheet remains strong. As shown on slide number 9, we finished the quarter with $461 million in cash and investments. Our financial position is solid, with leverage of 2.5 times trailing-12-month EBITDA, and interest coverage of more than 7.7 times the amount. Except for a 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 proceeds we received from the sale of our remaining Columbian E&P interests. Our ability to reduce that 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 than 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 nine rigs we were awarded last quarter that we announced. These changes have increased the estimated net debt to 30%, achievable by the end of 2013, which implies it will take another six to nine months, or approximately $680 million in asset sales, to reach our 25% target.

Now let me comment on the [fat] financial results. As we indicated in yesterday's press release and the pre-release 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 in 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 $293 million in non-cash 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 three 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 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 non-cash 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 year-to-date -- excuse me, $437 million for the quarter and year-to-date of $907 million. After we were awarded nine 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 (technical difficulties) 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 US lower 48 land drilling operations, which collectively brought this group down by $10 million. Our US lower 48 land drilling operations contributed 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 [ARC] 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 basin. 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 manufacturing drilling.

Drilling deeper into this group, let's first look at Nabors USA, the lower 48. Our US 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 one 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 in 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 US fleet is well-positioned in every major oil and gas operating region and is complemented by the strong US presence of our completion and production service business. As of June 30, 130 of our US rigs were drilling for oil, 41 for natural gas liquids, 36 for dry gas, and 3 for CO2. Once our scheduled new-build deployments are completed, our US 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 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 three 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 gassy to 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 three 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 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 of all 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 [networking] 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 next year on term contracts.

Now, let me turn to US offshore. Our US Offshore operation reported operating income of $10 million, up from $8 million in the prior quarter and significantly up from the $1 million loss reported in the second quarter of last year. This increase was driven primarily by gradually improving activity, as evidenced by a two-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 four of our platform rigs on reduced standby rates for work 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 $38000 to $42,000 per day in December of last year. Construction of the two 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 two rigs are the largest platform rigs ever constructed 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 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 come 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 a fully rigged up pad-to-pad move of over one mile using our Rig 103. This Rig uses a unique living system we refer to as a tabletop system, where we can move an entire conventional rig in one piece on a walking beam system. The operator concluded that 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 the rig moving down the road are at the end of the presentation, and it is 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 is a 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 US 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 [stair] decline 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. Both orders of spare parts from remote operations and a delay in the start-up of two significant rigs, one a high-margin jackup in the Middle East and another a high-margin land rig in the Far East, also contributed.

Increased depreciation associated with new and upgraded rigs, which 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 last of our four 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 all on the payroll.

Going forward, we are targeting improvement throughout the second half of the year and into 2013, especially with these rig redeployments 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 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 was subsequently canceled, is a good example, as are -- and there are similar examples in Iraq and in Venezuela. We also had several rigs which recently commenced new contracts that will shut down at a future time convenient to our customer for upgrade. The overall result is an environment of delay, cost creep, and unpredictability in the international market place, 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 are 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 [cap rig] 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 expiration program and maintenance and expansion projects on the North Slope. This business is 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 [800 and 5,000]. In the US, 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-day 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 in additional crew. In the US, we now have five 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 US and 2 in Canada. We have 10 crews working in the Bakken/Rockies, with 8 of the crews working under LTSAs. Two of our three Eagle Ford crews have LTSAs. We have two LTSAs crews and one spot crew in the Marcellus, and one LTSA and two spots in the Permian. Two crews are now on the payrolls 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 in balance. Will continue to proactively manage our spot-crew exposure, being careful that -- not to run rigs at too low yield -- 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.

US 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 in hourly rig rates more than offset the decline in truck hourly rates. The sequential improvement also reflected $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 US operating fleet consisted of 467 well servicing rigs, 1,020 fluid service trucks, and about 3,800 hundred 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 we'll 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 two 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 farming acreage in the 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 will now take your questions.

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

Thank you. We will now begin the question-and-answer session.

(Operator Instructions)

Jim Rollyson, Raymond James.

Tony, it sounds like on the international front, that opportunity is still around. You are still seeing interest levels in bidding for different parts of the world on rig activity. And it seems like the big challenge you have had is just 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, what your exit rate looks like for the international rig fleet at the end of the year?

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

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

Correct.

And on the domestic side, you gave pretty good color, I think, on the rig side of the business, some of the softness you've seen in leading-edge rates and terms shrinking down a bit. On the contract cancellations or buy-outs, 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 am curious if you are starting to see customers wanting to try and buy out more rigs. We've seen that in a couple of other guys so far. I am curious what you are seeing there?

We've had three, but I will have Joe comment.

Yes. The answer is we are seeing customers looking to buy out some contracts. I guess the answer is to date we had maybe six through the process that if they are not buying the contract out, the rigs were actually [owned]. As Tony mentioned, there's three rigs right now on payments through the month, which is which the contract allows.

And one of the things I think where you -- given our portfolio of assets, we are 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. We have a lot of other services that we can give people, and one of the benefits of doing some stuff with Nabors is the fact that we have a full range of other things to offer. So we are always looking to -- on one hand, we want to get the value for what we have invested in and received in the 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 is our job to manage that balance.

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

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 been able to redeploy those rigs. In some cases, we've got some commitments, but it is not near-term and maybe 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 have had the opportunity with a major operator that he chose to redeploy that term to Canada in lieu of the term in the US. So it's a great opportunity for our Canadian guys to have the contact, the structure in the US, I guess we used to call it metric days, have now been redeployed to the Canadian market.

Thanks for the color, Tony. Thanks for the detail.

Jeff Tillery, Tudor, Pickering, Holt.

In the slides, Tony, on the titles, is the US rig count at an inflection point? And I'm just curious if you could talk either basin or regionally where you think Nabors will show or is showing the more significant utilization weakness? (technical difficulty) compounded both your contracted and uncontracted exposure, as well as what the customers are doing. Curious where you are seeing the utilization weakness?

Sure, Joe --? (multiple speakers)

What regions are you seeing the weaker markets right now in utilization in particular, the industry and us?

The critical area for us right now is we are seeing -- there's still, although it is moderated, as Tony's comments said, in East Texas and Haynesville, that is actually strengthening of the gas market. That's abated. The Eagle Ford, we are seeing some weakness there, and that's mainly along the lines, as you mentioned, on natural gas [oil plays]. So there's areas across the US, and then the rigs that continue to deploy into the Bakken, although that is our strongest area that we're being impacted commercially by all the offers from other companies. But converse to that, there are areas that we find, Central Texas, some areas that we are seeing some improvement. And that is what, as Tony mentioned, we can't give an excuse, that we've got to find a place to redeploy the assets, and that's what we've done.

For the pressure pumping business, half the spreads on contract. Two questions along those lines. Are the spot fleets profitable from an EBIT standpoint at this point? If you can give us some color on when some of the contracts start to roll and when those additional spreads hit the spot market?

[Ronnie]?

Yes, I think that as far as pricing in the spot market, we are still seeing pressure, albeit maybe not as much in some of the dry gas markets, but as we're starting to see a rebalancing of assets, we are continuing to see some pressure in the liquid-rich areas. What was the second part of the question? A little color on the contracts. Outside of one LTSA that will expire at the end of this year, the rest will expire various points in 2013, with a number going into 2014 as well.

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 they are actually generating EBIT?

Yes, they are.

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

Utilization has got to be there, but the pricing as it is right now does not make it profitable for us.

Okay. Thank you, guys.

Waqar Syed, Goldman Sachs.

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

That was a -- it was -- those costs were dictated very centrally, and I think it was in response to macro issues going on with the region where the government 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 were forced to do it, just because it was mandated. 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.

What I want to understand was that a one-time bonus, or is that just that the salaries are being increased so every year, you have to pay an extra $5 million?

It was salary increases.

Actually, it was both. It was both. In some case, it was salary increases, and sometimes, it was a one-time deal. So it was both depending on the country we were in.

Okay. And secondly, as you look at your chart for the rig count decline 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 seven or eight rigs during this time period. And all the fall was on the vertical rig side. So is that consistent what you are seeing as well, more pressure on the lower end? And you mentioned some on the day rate side. But what are you seeing in terms of the activity? The vertical rig count, which maybe sometimes there's some seasonality attached to that as well, or overall --?

Yes, I think vis-a-vis us, 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 is also the horizontal. If the horizontal rigs are working and those things 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, possibly a moderate drop-off for that exactly the reason you've identified.

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

I don't -- when you say pessimism, I think that what I've tried to say is that it is almost the totality 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, it is almost [total logically] reason to be not pessimistic, but cautiously optimistic. But if you have the view of the reverse, then there is reason for concern. But you guys are as good, if not better, about figuring out what that -- 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 are just managing ourselves to handle the things that we can control.

Okay. Great. Thank you very much. That's helpful.

Jim Crandell, Dahlman Rose.

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 operator as it is even in hotter markets?

I think it's -- number one, I think it ought to be as desired. And number two, I think in the market that is more difficult, it ought to be even more desired, because I think the value proposition is greater. 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.

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

We've -- 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. 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.

Okay. Second question, Tony, you've been CEO about nine 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 nine months or so? And in general, is it easier or harder to effect change than you would've thought going in?

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 them. 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 compact through the Company is a lot of work, and it is not something that we'll be able to get done in a couple quarters.

But we've made a lot of progress on it, and we've brought in some senior people into functional areas, and we've brought some other in the operating areas in each of the business units. And people are delivering on that. At the same time, one of the visible things is the consolidation of Nabors Well Services and [Swizie], but we are 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. But it's -- as you've signaled, it does take a bit of time.

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

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

The way I would answer that question, Jim, is if you look at NFR, at a $4.50 gas price, they're economics start to look really different. Okay?

Okay, good.

That's one way of looking at it.

Okay, good. Thank you.

Operator, we're reaching our one-hour time-composed constraints, so we will take one more set of questions, please.

Scott Gruber, Bernstein.

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 US, close to 1,200, still well above the number of AC rigs that are operating, even if the active rig count leaps. Tony, you mentioned rates 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 where those rates can hold up and whether the appetite is changing given the shift toward more pad drilling and away from drilling to hold acreage by production?

I think for all the reasons we've spoken about today, let's not confuse a pause with the long-term business here. I think on the 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. 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 the 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. Just because there is a breather here, because of the shift and uncertainty as to where -- what kind of environment we're in, I still think the overall game hasn't changed.

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?

The first thing is that our SCR rigs -- a lot of our SCR rigs, as I mentioned, have already been refurbished with what is called a K-Box, which is a Canrig tool. And when you put this on a rig, it basically gives that rig the functionally of an AC rig, and so 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 kind of rigs, there isn't much of a gap. But in other areas, the gap could be anywhere from 5%, 10% delta on the day rate.

Is that where you think the spread will stay? Or do you think it could widen some?

Over time, I think it will widen.

Okay. Very good. That's all for me.

Operator, that concludes our questions answer, if you want to close the call out, please?

Thank you. Ladies and gentlemen, this concludes the Nabors Industries Limited second-quarter 2012 earnings conference call. This conference will be available for replay. 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.