Nabors Industries Ltd (NBR) 2013 Q2 法說會逐字稿

Welcome to Nabors Industries' second quarter 2013 earnings conference call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session.

(Operator Instructions)

I would like to remind everyone that this conference is being recorded today. And I would like to now turn the conference over to Mr. Dennis Smith, Director of Corporate Development. Please go ahead.

Good morning, everyone and thank you for joining our second-quarter earnings conference call this morning. We'll follow our customary format, where Tony Petrello, our Chairman and Chief Executive Officer, will give our perspective on the quarter's results and some insight into how we see our business in the markets that we worked in evolving in the future.

In support of his remarks today, we have posted some slides to our website, which you can access to follow along if you desire. They are accessible in two ways. If you are participating by webcast, they are available as a download within the webcast. Alternatively, you can download them from our website at nabors.com under Investor Relations, in the submenu events calendar, and you will find them listed as supporting materials under the conference call notice for this morning.

In addition to Tony and myself today are Laura Doerre, our General Counsel, Clark Wood, our Principal Accounting Officer, Sri Valleru, our Chief Information Officer, and all the heads of our various business operations. Since much of our remarks today will concern out expectations of the 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 Exchange Act of 33 and 34. Such forward-looking statements are subject to certain risks and uncertainties as disclosed by Nabors and its filing from time to time and we encourage you to read those filings for the Risk Factors involved.

With that, we'll get started, and I'll turn the call over to Tony.

Thanks, Denny. Good morning, everyone. Welcome to our second-quarter conference call. I would like to thank everyone for participating this morning.

As Denny said, we have posted to nabors.com a series of slides that contain details about our business, the performance of various segments, and other relevant information. I will refer to some of the slides by slide number as we proceed.

As you know, we pre-announced our earnings two weeks ago as we became aware that, on the whole, we would under-perform both the Street's and our own expectations. This under-performance was disappointing, and was principally driven by the Canrig portion of our other rig services segment and the US pressure pumping portion of our Completion Services segment.

The underlying causes were an abrupt decrease in third-party capital equipment deliveries for Canrig, and historic weather conditions in the Bakken, where we have a uniquely high concentration of our pressure pumping crews. We will talk in more detail about the circumstances later, but I first want to make sure that the under-performance of these two segments does not overshadow the several positive achievements we had in the quarter. On that note, I'd like to highlight some recent accomplishments and events before we go into the operating results.

First, the topic of debt reduction. Through a combination of net operating cash flow, cash on hand from liquidated securities, and a reduction of working capital, we were able to reduce gross debt by $302 million and net debt by $219 million in the quarter. As shown on slide 4, this brings our net debt-to-cap to 37%, leveraged to 2.4 times trailing 12 month EBITDA and interest coverage of 7 times that amount.

Based on consensus EBITDA estimates for the remainder of 2013 of $850 million and CapEx of $691 million, and continuance of our stated dividend of $0.04 per share per quarter, and third-quarter interest payments, our net debt-to-cap will be the same as the end of the year, exclusive of any asset sales. Since our peak debt level of $4.8 billion 18 months ago, we have reduced total debt without, frankly, sacrificing the earnings power of our asset base by nearly 50% or $690 million, and net debt by $822 million.

One point I would like to continue to emphasize is that enhancing the flexibility of our balance sheet is not our sole focus. We do intend to continue to generate EBITDA in excess of capital expenditures to reduce net debt, which should positively affect the equity component of our enterprise valuation and the stock price. However, reducing our net debt amount will not prevent us from funding capital projects that improve our competitive position and are in line with our capital deployment criteria.

One example of these capital projects is our PACE-X new build program. Turning to PACE-X performance, we now have five PACE-X rigs on revenue, three in the Haynesville, one in the Marcellus, one in south Texas. And they are performing above our already high expectations. As would be expected, there were some small issues that had to be worked out of new technology concerning electric motor controls with the first two rigs, but they are now exceeding expectations.

The three rigs in the Haynesville Shale have delivered considerable improvement over wells drilled by AC rigs in the same field within the last six months. Inclusive of downtime experience, within the intermediate hull section, our PACE-X rigs have reduced average drill time by 26%, and the best intermediate hull section was completed in half the time of the previous average. Total well times have been reduced by an average of roughly 15%, and the best total well time was reduced by 35%. Increased RLP has been the main driver of these drilling time decreases, and our enhanced rig equipment and rig software are responsible for that.

The performance of the PACE-X and our skilled crews is resulting in increasing interest for the rig, and I am pleased to announce today the signing of two more long-term take-or-pay contracts for new build PACE-X rigs. Referring to slide 5, this brings our total number of PACE-X new builds to 21, with 16 of these yet to be deployed.

Next point I would like to emphasize is that the US is not the only place presenting opportunities for us to deploy capital. We have had good success in gaining long-term take-or-pay contracts in key markets outside the US.

We were recently awarded contracts for six upgraded 1,500-horsepower AC rigs in Argentina, two upgraded 3,000-horsepower rigs in northern Iraq, and one upgraded 2,000-horsepower rig in Kazakhstan. Including the two new build awards, these oil rigs represent average take-or-pay terms of 3.2 years. They consist of $150 million in new capital, and should generate over $600 million in revenue. This equates to attractive returns on capital, inclusive of their existing book value.

Discussion about international awards provides a good segue into how we currently see the rest of 2013 and 2014 shaping up, and the underlying trends driving these opinions. We believe that international rig market is finally emerging out of an extended trough. Ultimately, it has taken longer than what we thought. Consistent utilization is driving our near-term positive yield while gradually tightening of rig supply through sustained increases in rig count should lead to higher day rates in the intermediate and longer-term.

The international land drilling industry has, for the most part, experienced anemic returns since 2009, and appears to be wisely reluctant to deploy capital for new builds, given the recent economics. Once new builds become economically viable, we expect that they will pull other renewal rates up with them, much like what happened in the US market starting in 2005. At this point, today, the under-supply of rigs is country-specific, and our current contracts in these limited countries are generally not scheduled to renew until mid- to late-2014. Nonetheless, we are positive on the international market, but as always, the pace of which any this is realized is subject to geopolitics, the global macro environment, and in some cases, local government procedures or the lack thereof.

On the US front, the increased efficiencies of drilling rigs and pressure pumping crews re showing signs of two significant consequences. Drilling more wells with fewer rigs, and customers consuming budgets quicker than expected. As you can see on slide 6, from the recently published Baker Hughes well data, the number of wells per rig has increased substantially. For the entire US, from first quarter 2012, which is soon after the cycle-high rig count in November 2011, to the second quarter of 2013, the amount of wells per rig has increased 9%.

When looking at only Eagle Ford, Haynesville, Marcellus and Williston combined, which could be considered the most mature shale plays, the increase is 34%. There is growing evidence that the same is happening in pumping, due to the increased institutional experience of operators in their main basins. One example is that a customer of ours is pumping as many as 15% more stages per day using zipper fracks versus using single well operations last year. This is just one example, but the combination of pad operations, sliding sleeves, coil fracks, and other technology developments is noticeably increasing efficiency across the industry.

The other noted consequence that could affect both drilling and completion services later this year is that operators are consuming their annual budgets more quickly than expected, due to drilling efficiencies, pumping efficiencies, and the availability of completion equipment. If our customers do not right-size their budgets to the new pace of spending, or to account for the additional cash flow, they are receiving, particularly from the oil plays, that we can see a drop-off from the fourth quarter similar to what was experienced last year.

A recent survey by us of our customers has confirmed these concerns. Generally, the view amongst the customers was that the most expensive part has been completions. Most customers are over budget due to efficiencies. With the exception of a few, most are planning to reduce rig count in the second half to stay within spending guidelines if they are out of pace, and most expect 2014 budgets to bring increased activity.

Given this outlook, here are our priorities. We will seek to grow in a flat US drilling market by continuing to differentiate with technologies like the PACE-X rig and operational excellence, as well as by marketing our legacy assets, based on the value proposition of safety efficiency, not just rate. We will focus on right-sizing our costs to our current cash flow, and we will continue to work on disposing our E&P and other non-core assets so that we are focusing on efforts that are only quarter Nabors.

Let me turn to the financial results, on slide 7, for the quarter. EBITDA was $361 million, down from $423 million in the prior quarter. Approximately $51 million of this shortfall was due to seasonal aspects of our business, namely Canada and Alaska operations, in both drilling and rig services, and completion and production services, while sequentially better in international offshore, were almost entirely offset by declines in Canrig and US pressure pumping. This led to operating income of $91 million, down from $150 million last quarter.

Our earnings per share from continuing operations were $0.08 per diluted share. The quarterly EPS benefited from a lower tax rate, 17%, primarily due to the mix of income with international up and US down. We expect the remainder of 2013's effective tax rate to be approximately 16%, and cash taxes should remain at minimal levels.

Our capital expenditures for the quarter were $272 million, including sustaining CapEx of $94 million. Depreciation for the quarter was $270 million. For the full year of 2013, we expect depreciation of approximately $1.1 billion, and total CapEx of about $1.2 billion remains unchanged.

Of note, sustaining CapEx for the year is expected to be $351 million, which is down $60 million from 2012 as we continually work to right-size our spending to current activity levels while also maintaining the integrity of our equipment. We will continue to focus on optimizing our growth and sustaining capital plans, and are prepared to increase our budget to fund opportunities with attractive economics that serve our customers' needs.

To summarize the quarter, we have generated net operating cash flow, which is EBITDA less CapEx, of approximately $90 million. We still expect to generate similar quarterly levels of net operating cash flow through the remainder of 2013, not including asset sales, despite weaker North American market conditions. We will continue to focus on executing sales of non-core operations and are optimistic of more progress on that front before year-end.

Now I'll turn to each of the segments for a deeper dive. First, drilling and rig services. This group, as you know, consists of our land drilling operations, offshore rigs, specialized rigs, drilling equipment, and manufacturing drilling software and automation and directional drilling operations. In the second quarter, this group generated operating income of $102 million, down from $137 million in the first quarter. Customary seasonal weakness in Canada and Alaska, and the decreased demand for rig services, was marginally offset by better-than-expected results in the Gulf of Mexico and in international drilling.

If you turn to slide 10, it shows the current status of our substantial worldwide drilling fleet. Including rigs scheduled to be deployed, we have 216 AC rigs, including advanced deepwater platform rigs and remote location rigs in the Arctic and internationally. Slide 11 highlights our utilization during the quarter. It is worth noting that 78% of our Lower 48 book value is attributable to our AC rig fleet, which is utilized at 95% today. With our global footprint, we can capitalize on relocating rigs from under-utilized or under-priced markets to higher demand markets, an advantage we have over our North American-focused peers. An example of this is our fulfilling a portion of our Argentine rig award with three AC rigs from the US.

In the Lower 48, we currently have 58 rigs available to go back to work that fit the sweet spot in rig demand, namely in the 1,000 to 1,500 horsepower range. 52 of these are legacy rigs, which we are seeking to place in the sideways market by selling our value proposition. A portion of our Lower 48 fleet is high-quality, 2,000 to 3,000-horsepower rigs. While these currently have little demand in the US, they can satisfy future international requirements with additional capital for appropriate upgrades.

We have seen an improvement in our US offshore utilization as compared to recent quarters. Our Super Sundowner platform work-over rigs and our platform drilling rigs remain highly utilized. Additionally, we are well-positioned to capitalize on the expected increase in activity in Alaska, and to enhance the utilization of our technically advanced industry-leading Alaska fleet.

Our Canadian utilization reached its usual second-quarter seasonal low. Utilization will continue to be impacted by the drilling rig supply in balance in Canada until natural gas drilling resumes to meet LNG commitments or until there is a resurgence in commodity prices.

Our international fleet has experienced improved utilization as compared to recent quarters. We see our available rig inventory as a valuable option as increased international land rig demand materializes, this leads generally higher prices. Our rigs should be particularly effective, given that the market supply of some of our high-spec rigs is minimal. For example, we are filling a portion of our Argentine award with two AC rigs from Colombia, and one SCR rig that was last operating in Libya.

Now I'd like to go deeper into the segments, first, US drilling. Our US drilling segment earned operating income of $70 million, down from $78 million in the prior quarter. The sequential variance was due to a nearly 50% increase in offshore, offset by slightly worse results in the Lower 48 and traditional seasonal declines in Alaska. We expect this to be the bottom for our Lower 48 operation, as spot pricing has largely worked its way through the fleet and contract roll-offs have decreased considerably from the 2012 pace.

During the second quarter in the Lower 48, we added six rigs, but our average margins for the fleet declined $567 per day, which was a number less to what we signaled on the last conference call, finishing the quarter at $9,388 per day per rig. Margins were better-than-expected, primarily due to our measured approach to putting underutilized assets back to work, and partially due to the resiliency in spot market rates.

Since our rig count bottomed in the February of this year, we have reactivated or deployed 18 net rigs, 8 of which were done before the end of the first -- since the end of the first quarter, and 6 since the end of the second quarter. These rigs were not concentrated in any one region, but were spread across all of our operating regions, with the exception of the Rockies and Northeast, which saw net decreases. A number of these rigs were AC rigs, which went back to work at average day rates of $22,265.

Today, we have 183 rigs on revenue, including 8 on standby rigs, Of the rigs, working 134 are AC and 101 are pad-capable. As of today, our AC rigs and our pad-capable rigs are both 95% utilized.

We deployed 5 PACE-X new builds year-to-date, and have 16 more scheduled to deploy on long-term take-or-pay contracts through the remainder of this year and early 2014. Pad drilling capability is one of the strength of our Lower 48 rig fleet, as we've previously remarked to you. We currently have 121 rigs capable of pad drilling, 91 of which are walking that allow multi-directional walking, and 30 of which have skid systems. After completion of plant upgrades to walking systems on existing rigs, and completion of PACE-X new builds, we will have 143 pad-capable rigs, 116 of which will have multi-directional walking capabilities. It's important to note that we receive a premium for pad-capable rigs as well as a higher utilization.

Depending on the region, AC spot rates continue to be in the range of $19,000 to $24,000. Sequentially, spot rates were mostly flat to slightly up for AC rigs, in the range of $500 to $1000 per day, depending on the region, with the latter seeing in Ark-La-Tex and Gulf Coast. Legacy spot rates were in the range of $16,000 to $21,000, again depending on region, and were mostly flat sequentially with the exception of a slight increase in Mid-Con and $1,000 drop in West Texas.

The West Texas market is undergoing a transformation to a horizontal market at the expense of legacy rigs that have been operating in the region for many years. We are meeting this challenge by relocating AC rigs to this region to match demand. Our PACE and 1,000-horsepower fast-moving rig is particularly well-suited for this market. In fact, since the beginning of this year, we have moved 10 AC rigs into West Texas.

With the lack of significant movement in the industry's rig count so far in 2013, we anticipate pricing to remain generally flat in the near-term. However, we intend to help mitigate the financial impact by increasing utilization of legacy assets, as well as whatever existing AC rigs we have. We had 24 term contracts expire in the second quarter. Of these, 17 were extended for an average of seven to eight months on rates of $21,000 to $22,000 on average. Six went to spot market with similar rigs, and one was stacked.

We believe the impact on our margins due to term contracts rolling to lower spot rate has moderated significantly from last year, as we have an average of only 16 rigs expiring per quarter in the second half of the year, compared to double that amount per quarter in 2012. We expect sequential margin compression in the third quarter of $400 to $500 per day due to these expirations.

We have been cautious, as you know, over the last year, on industry productions of a market reset since the beginning of the year, and we're equally cautious about a second-half rebound. We expect the industry rig counts will remain flat for the remainder of the year. However, we are focused on our making count higher by the end of the year. That said, our optimism remains tempered, given efficiencies and budget concerns.

Turning to offshore, the sequential figures have increased. This operation was due to increased utilization, as well as cost reduction resulting from the previously-announced organizational consolidation of our US operations. We worked 15.6 rig years during the quarter compared to 14.1 last quarter, and earned a $1,700 per day increase in daily margins, nearly $21,000 per day. The third and fourth quarters have becomes seasonally challenged for this business, as the majority of our customers suspend rig work during hurricane season and are slow to recommence in the fourth -- in the face of fourth-quarter holidays.

Turning to Alaska, our Alaska operation posted seasonally lower results than expected. Alaska has become highly seasonal, with little year-round drilling work being conducted in the legacy North Slope fields, where progressive tax rates limited reinvestment for the last several years. However, the recent tax change should spur additional development drilling, and has the potential to return a number of our existing rigs to full-time work. We currently have eight rigs that require minimal capital to go back to work quickly that we are marketing.

In the long-term, numerous strategic projects are planned in areas where exploration and development tax incentives are in place. But these are characterized by long lead times, and will likely not commence for another two years or so. It's important to note that opportunities in Alaska are generally three to four times more profitable per rig than similar contracts in the Lower 48.

Turning to Canada, our Canadian drilling segment posted operating income of $4 million, down from $31 million in the seasonally high first quarter, but up from essentially breakeven in the second quarter of 2012. Rig activity decreased sequentially by 23 to average 17 rigs operating in the first quarter. Margins increased slightly over the prior quarter and averaged nearly $15,000, which is the highest margin we've ever seen in Canada, driven mostly by the demand for deeper, higher spec rates, which account for the majority of our fleet. In the short-term, the same spending constraints and outlook witnessed in the Lower 48 are weighing on the Canadian market, and any positive signs in the US should be reflected positively in Canada.

The Cardium continues to be characterized by an oversupply of smaller rates, putting downward pressure on rates. Operators in the Montney and the Horn River, and Fort Liard areas of British Colombia, have been slow to release their winter drilling programs, and competition is high among contractors. However, we recently deployed four rigs for early phase LNG drilling directed in and around British Columbia. We expect these deep gas fields in BC to grow over the next few years as customers begin to ramp up their LNG-directed drilling. In the near-term, we expect the seasonal ramp into the traditional first quarter high to be at least as steep as last year's ramp.

Turning to international. International posted operating income of $32 million, up from $21 million in the second quarter and double the second quarter of last year. The sequential increase in operating income resulted from an activity increase of 2.5 rig years, a margin increase of nearly $1,000 to $12,400 and change per rig day. And the mitigation of operating costs in several challenging countries, namely Iraq, Yemen and Colombia. Further, these costs were mitigated by either improved utilization or increased day rates.

As we said before, we expect this quarter marks the exit from the extended trough that as characterized the international markets since 2009. We expect to see further improvement in the third quarter as we see full-quarter contributions from Super Sundowner 10 in Mexico, the startup of one of the recently-awarded AC rigs in Argentina, the startup of two recently-awarded rigs in northern Iraq, and the return to work of one rig in Algeria.

Improvement through the rest of this year and early next year will be driven by further mitigation of extraordinary operating costs in the mid-2014 start up of the five remaining rigs for Argentina and one rig for Kazakhstan. Longer-term improvement will be driven by the overall tightening of the rig market in the face of growing markets in the Middle East, namely Saudi and Algeria, as well as Latin America, and the resulting increase in day rates and the demand for new build rigs. However, these markets can be unpredictable, and decisions or tenders are frequently delayed, such as the recent 27 rig tender for Saudi, which has been delayed by two months so far, which could delay activity by four to six months.

Turning to the rig services segment, our rig services line, which includes Canrig, Peak and Ryan, posted an operating loss of $4 million in the June quarter versus income of $8 million in the prior quarter. Before we detail Canrig's performance, let me address the other operations of rig services. Combined income from these operations was in line with our expectations. Recall that we normally see a falloff in Alaska-based operations in the June quarter, as warming weather inhibits operating tempo. These operations account for over 40% -- 43% of the sequential decline in operating income.

Now let's move to Canrig. Reflecting a broad slowdown in new rig building activity, Canrig's equipment shipments declined during the second quarter. In particular, third-party shipments of top draw dropped by more than 50%, reflecting lower customer interest in new build rigs, as well as the deferral of some shipments.

Canrig's non-equipment revenue, principally rentals and service, declined by 10% as drilling activity eased. We foresee an uptick in Canrig beginning this quarter, supported by sequential increase in top draw shipment, and into the future, supported by our proprietary automated pipe-handling equipment. We have remained enthusiastic about Peak's prospects for increased activity levels as the effects of the Alaska tax change are realized. Projects in Alaska are large and complicated, with long development cycles. Regardless, judging by our discussions with customers, interest in new projects is high.

Turning to completion and production services, this business line obviously consists of services that complete and maintain wells, including pressure pumping, well servicing, work over, and coil tubing rigs and fluids management. Operating income for this division is tabled out on slide 16. Completion and production services posted an operating income of $30 million, down from $44 million in the March quarter. Completion services operating income of $7 million for the June quarter was down from $18 million in the prior quarter, reflecting in part a loss in Canada due to breakup.

Results of this operation more impacted by the combination of abnormally severe weather in the Bakken and growing pricing pressure, especially in West Texas, and to a lesser extent in the South Texas market. Of Nabors 18 frack crew currently operating in the US, 13 are located in the northern half of the country and 6 of those are in the Bakken. As the Director of the oil and gas division of the Department of Mineral Resources in North Dakota commented, April 2013 was the coldest on record and May 2013 is the wettest on record. Our operations were not immune to extraordinary delays associated with these conditions, including extended road bans. Three of our spreads in the region were shut down by weather for 10 to 12 days each month of the quarter, that's about 100 potential revenue days lost.

In the Southern Region, we continue to see challenging market conditions. It is not unusual to bid frack jobs against 20 other pumpers, and sometimes as many as 35 show up. We have seen some instances of competitors winning bids with economics that, at least from our perspective, appear to be near cash breakeven.

Referring to slide 18, we now have 18 crews working in the US and 2 in Canada. Of those 18 in the US, 11 are 24-hour crews and about 50% are working on pads. Given market conditions, we recently added another spread in the US. Most of our long-term service agreements have now been reset.

We have eight crews currently working under service agreements, which provide some visibility to customer work plans to the beginning of 2014. The last two of the large crew working under legacy term contracts will roll off in Q1 of 2014. As contracts have rolled off, we re largely continuing those relationships and continuing to work for those customers, even as we look to add to our customer list.

As for Canada, we have two start crews working in that market, which will also remains challenging. We have to stay (inaudible) in the face of this difficult market conditions, our June stage count was the strongest so far in 2013, and July is keeping pace. However, pricing pressure does continue, and the number of players still is extraordinary.

On the technology front as we have done with drilling, we are now in the process of introducing dual fuel capabilities into our fracking operations. We also recently closed four facilities and continue to review the assets deployed in this business. Our efforts to improve working capital management are paying off with improvement to DSO and days of inventory. Our efforts to bring efficiencies to [rib] dollars out of the G&A line continue to pay off.

This quarter's annualized run rate of $122 million is about $20 million less than the run rate in the second quarter of 2012, which was before the consolidation of the services and well servicing operations. However, we are not done, and currently have initiatives under way to continue improvement in our cost structure in this business.

In light of challenging market visibility in spot markets and the continuing industry-wide horsepower supply demand imbalance, our outlook remains cautious for this business. Apparent efficiency gains to this business and, of course, other service lines, have the effect of lowering our customers' per-well cost while consuming the budgets more quickly than planned. Those pick-ups in efficiency are coming from multiple sources, including zipper fracks I mentioned, which increase the number of stages the fleet can pump per day. These are facilitated by pad drilling, which reduces moving time between wells and enables parallel fracking operations.

Increasing 24-hour operations also expands industry fracking capacity. Some customers are already signaling that they're spending could tail off before the end of the year due to this more rapid spending pattern. The question remains which, if any, customers will revise budgets in light of higher commodity prices and the ability to bring more production online faster than before. Our recent survey of our customers indicates most large customers are not currently planning to add to 2013 budgets.

Turning to production services, production services' operating income of $22 million was down 10% from $26 million in the March quarter. Revenue and rig hours increased in the US, offset by a sharper than expected seasonal drop in Canada. Rig hours in the US increased, despite the weather in the Bakken, which accounted for about one-sixth of our US well servicing rigs.

As shown on slide 18, at the end of the second quarter, our US operating fleet consists of 442 well service rigs, 1,036 fluid-service trucks, and almost 3,600 frack tanks. In June, our rig utilization was 78% up from 66% at the beginning of the year, and our truck utilization was 73% up from 70% at the beginning of the year. Even though well servicing and fluids management market remains competitive, particularly in the Texas markets, which continue to attract capacity, our diversity across basins is a real asset to Nabors' footprint.

We see growth near-term in part thanks to seasonal improvement in Canada, as well as longer-term. As the population of horizontal oil wells reaches critical mass in ages, it will still need maintenance and other interventions. Much of the work on these wells will require a larger service rig capable of reaching into the long horizontal section. Also, we believe the customer base defined by this inventory of wells will demand high levels of field safety and environmental performance that smaller competitors will be hard-pressed to deliver.

So in summary, while international appears to be emerging from an extended trough due to mitigation of costs and near-term deployments, North American market remains uninspiring. Accordingly, we are focusing on the things we can control. We will seek to grow on a flat US petroleum market by continuing, as I mentioned, to differentiate ourself through technology and particularly through the advantages Canrig brings to us, and marketing our legacy assets based on a value proposition.

We will continue to focus on EBITDA generation, extracting the most that we can from our current asset base, as you've seen, focusing in particular on our international base, our existing asset base, and getting to be folded into profitable contracts. We will focus on right-sizing our costs in all of our businesses to their current cash flow levels. And we will continue to dispose on -- work on disposing our E&P and other non-core operations so that we are focused only on businesses that are core to Nabors and that offer long-term scale and upside.

So with that, that concludes my formal remarks, and we'll take your questions. Thank you.

(Operator Instructions)

Jim Crandell, Cowen.

Tony, could you give us an update on the asset sales? I realize asset sales can take a long time to accomplish, but even given that, it seems like this is dragging on and on. Maybe you could -- and if you could -- to put some kind of broad number range or timeframe range around the expected sales?

We have, as you know -- the principal asset [clefts] are the E&P assets of the Eagle Ford, Alaska and Horn River. All three of those are with packages, with people, and being looked at and marketed actively. And as I mentioned, I think, I'm confident that you will see some progress on that very shortly. So then the other one that is been marketed is the Peak logistics operation in Canada, as well. I think that you are going to see some -- we're hopeful of seeing some results on that very shortly. So all four of those are in process, and I think Alaska -- oil properties in Alaska and the Horn River in Canada probably are the most challenging, given the special circumstances that both markets, the number of players that are in -- available in Alaska, participate in Alaska. It's not as deep. And Horn River, of course, with the gas price the way it is, the trapped gas makes that more problematic. However, the recent developments up their with Apache and Chevron, and the whole area, I think people have now seen a path to LNG, and that makes the prospects very much more attractive. So we're hoping that that will change the situation.

Okay. On that topic of LNG, Tony, there's been some talk recently about there potentially being several new build announcements coming out of Canada here in the second half, or startup of some delineation drilling in the Horn River beginning in 2014. Are you seeing that? And what to expect in terms of new builds announcements in Canada?

I think there are inquiries out there on new builds, and we are looking at them. As I mentioned, we are -- we actually just -- we just deployed a bunch of assets there that are directed at that, and we understand, principally from the two people I just mentioned, there is some large amount of demand for the programs that are [constant] up there. So I think that is the case. The question in Canada is the rate structure and the economics, because as you all know, the drilling season up there is the short drilling season, and the question is to make numbers work on the short drilling season for term contracts. But we are looking at it.

Okay. And Last question I had, Tony, is could you talk a little bit about the future of your SCR rigs, given the continued rig efficiencies and the move to -- increasingly to AC drive rigs? And maybe what has to happen, or would there be any potential widening of the day rate spread between SCR and AC drive rigs in the marketplace?

That's an interesting question. We have our SCR plus rigs, which are SCR rigs with a Canrig special package that makes it look like an AC rig and perform like an AC rig. We are enjoying 55% utilization on that category of rig. And the delta in day rates is maybe $1,000 a day or so. So it's not that wide. I think the SCR rates, the SCR rigs in terms of drilling with the -- certainly with that Canrig package, I think are effective alternatives where moving is not a big part of the equation. Obviously, the legacy rigs don't have the advantage of the structural steel being designed to be fast-moving. So for those operators, though, that that's not the driver, those rigs are attractive. In fact, that's what we're hoping to do in terms of marketing legacy rigs, spending more time marketing that. And we're doing that in a bunch of regions, like the -- obviously, the Bakken area and the Northeast, and maybe even some of South Texas. So the other interesting thing is on the Saudi. The Saudi tender, which I was focusing on, that Saudi tender doesn't specify AC rigs. And --

International in general.

And international in general doesn't (multiple speakers) specify AC rigs. And so the fact -- it's really remarkable, actually, that they view other things as more important to the drilling process in those plays, at least up until now. Whether that changes, I can't say. But up until now, that's not part of the requirements. So therefore, as we've mentioned, we uniquely have an install base of a bunch of 2,000 and 3,000-horsepower SCR rigs, which can be the platform for tendering that -- to those markets. So -- and that's what our focus is, to try to get the utilization of existing assets.

Okay. Interesting.

Mike Urban, Deutsche Bank.

Tony, from your comments on the prior question, it sounds like this is the case. But just wanted to confirm that the opportunities that you took advantage of in Argentina to move US rigs out, or -- and potentially even some older rigs out of the US and into the international markets was not anomalous or one-off. And again, just wanted to confirm that you do see additional opportunities to do things like that?

That's correct. Historically, a lot of, in the early days, back when international was growing and US was at best sideways, we redeployed a lot of those rigs to the projects, particularly in the Middle East. So we have a well-oiled machine that can do that and, as I mentioned, I think the shrinking supply of rigs in the international market makes that a possibility. I think the question for us will be, it depends on the opportunity. If the rigs that are spec-ed have so much new stuff with the amount of new content becomes so overwhelming, and do you want to do that to a base rig that's old, as opposed to leaving that base rig and finding something that requires less CapEx to deploy into a market, to be productive and spend all new money on a rig. So that -- you have to do that kind of balancing in terms of looking at the issue. But in terms of the -- out in the fairway, yes, those rigs are -- those 2,000 SCR rigs right now, those massive substructures we have? They fit the Saudi specs, for example.

(inaudible) advantage on delivery.

And as I said -- I don't know if you can hear Siggi, but as he said, this also gives us an advantage on delivery with some of these international projects where time may not (technical difficulty).

What are the relative economics of that? So sounds like you can get the same type of rates on these substantially new rigs. As you said, most of it is new stuff. What's the relative cost there? You have the time advantages, there are cost advantages as well, presumably, from using that older rig?

It's obviously a cost advantage, because the base rig, you don't have to spend any new dollars. But, since that base rig -- when you look at the economics, though, you should look at that as a mark-to-market item that you want to get some return on that as well. You still don't want to give that away. So -- but yes, there's saving of a base rig and, as we mentioned, there is a time advantage.

Right. And then last question was, you gave us a number of anecdotes on cost savings and efficiency improvements from the reorganization of the business you have been doing. Do you have anything in the aggregate that would tell us how much you think you've saved or how much -- maybe how much margin improvement? And better yet is, how much of that is still to come? It's just difficult for us to disaggregate with all the different moving pieces in the market.

I think from the -- I think as I mentioned in the US, I think we've taken out about $3 million to $4 million in the overhead in the US operation. And we've taken out about $20 million of overhead in the pressure pumping, well services operation. And as I've mentioned, that's just beginning as far as I'm concerned. We have a bunch of initiatives underway to really look at the whole thing. So that's a real priority. Given our scale, we think we should be able to operate as efficiently as anybody. And that's what we're going to do. And you can see the change in our working capital with the DSO, for example, reflecting some of those things that are going on now. So, that -- so I don't have an overall number yet to give people, but that's am active project right now.

And would you say you are halfway through that, three-quarters, or still in the early stages?

I'd say we're early-stage of the -- what I just referred to.

Okay, great. That's all for me.

Robin Shoemaker, Citi.

I wanted to just ask if you could give us a little further commentary on your statement about E&P companies over-spending their budgets here in the first half of the year? And seeing the possible slowdown. Now most of the year, most of the service companies drillers have called for flattish rig count through the end of the year. But clearly, last year, if we have a repeat of last year, then we will must see a declining rig count in the fourth quarter. Would you -- is that your expectation? And is there any steps you need to take to anticipate that, so as not to see a further erosion in your margins?

I think the first thing is, as I mentioned, I think that most companies that are over budget are attributed to efficiencies, and with the exception of just a minor portion of our customers, most are planning rig reductions in the second half. So, that -- those are realities that we have to cope with. And the best way to cope with them is execute better and not be the one to get turned off the payroll. So --

Okay. So in a -- as you indicated, you want to gain share in a flat to declining market. Is that -- is price the real driver there, for either the AC drive or more conventional rigs?

We're in the business for price is always relevant. But I think people have to look at the delivered value of the well. And I think what I was saying at least, particularly with the legacy rigs like SCR plus rigs, or even, frankly, some mechanical rigs we have, the ability for us to drill wells efficiently in certain regions, given our long experience in those regions, is really quite unique. In fact, there's -- one of the banks has an analysis of drilling efficiency by region, where you see the full rigs in Marcellus, the Bakken, Eagle Ford and one other one. But when you look at their analysis, and particularly in the Bakken, and you see our drilling efficiency in terms of days to drill compared to our leading competitors, you'll see that we are in the leading position. And based on the fourth-quarter data that's available, and -- so I use that just to say that the interesting thing is our fleet up there has a large chunk of legacy rigs that we're still able to do that. So it's not just the new rig that matters. It also is all the things you have behind it. I think that's something we can sell.

And in this environment you see in the second half, do you think this AC drive spot rate that you mentioned is $19,000 to $24,000, that that would hold in that range?

I think we've been successful at -- as I said, we're holding these over at $22,000 and -- I mean between $21,000 and $22,000 and the incremental ones we deployed was at $22,000 and change. And that's where we think the market is right now.

Okay. All right.

Jason Gilbert, Goldman Sachs.

I was wondering, maybe if you could put a finer point on Lower 48 land rig supply and demand. You have mentioned speculative new building by competitors in the Press Release. I was wondering how many new builds you see out there, industry-wide? And then, the follow-up is, how much attrition do you expect that the US land fleet over the next couple of years?

I don't have a specific number of new builds coming into the market. We've -- of course we can identify the rig count that we have and, as Tony has mentioned, we're going to take advantage of the opportunities to redeploy assets, if the economics make more sense overseas. But again, the US market is -- the AC rig has done a phenomenal job and -- but as he mentioned, some of our legacy assets also are very competitive in markets where you're not -- the drivers is not specifically moving between pads or between wells. So again, the AC rigs are, again, the efficiencies have spoken for themselves.

Yes, more to your -- to the core of your point there. I don't think we have a good handle. No one has a really good handle on what the actual attrition number is. And in terms of what's in the pipeline, whether it was 50 or 70 new AC rigs out there with the number that was floating around. I think the question is, how many of those have been absorbed this quarter. I guess we'll see when people start reporting. And the other question is, as operators' plans change, how many currently rigs that are on long-term contracts are going to come -- kick loose. But as far as I can see, given what we've experienced with Canrig, I don't see a lot more new building coming on so -- in terms of increments from today. As far as -- I haven't heard a lot more new building. There's one leading company that talks about continuing a cadence of maybe two rigs a month, but other than that, I don't know of anything out there suggesting a lot of new building in this market.

Okay, that's helpful. I was expecting it either, but I did see the comment in the Press Release, so I wanted ask. The next question I had is, I like the fact you paid down some debt in the quarter. Basically you're implying your view is basically that equity holder and bond holder interests are aligned right now and that reducing leverage will help the stock price. Did that -- I was just wondering, what level of leverage do think you would have to get to where that would stop being the case, and you'd think about more directly returning cash to shareholders?

I think we said (technical difficulty) historically being in the mid-20%s or high 20%s, mid- to high-20%s, would get us to the level that we aspire to, that historically we're at, so that's where we'd like to be. But you're right. I think we [view] today, there's an alignment between reducing debt and the equity holders, because frankly we trade on an enterprise value basis. And I think also that the premium we enjoyed may impact be a little bit correlated to -- inversely correlated to the debt level. And so, hopefully as the ratio goes down also, that ratio would improve on top of it. So that's the thinking.

Right. That's all I've got.

Operator, we are approaching our one-hour time. I think we will limit to one more question, please.

Marshall Adkins, Raymond James.

Being the last question, I'll try to summarize what I thought I heard today, and if you would just confirm whether I got it right. US land business flat, troughing, probably not getting a whole lot better. International, gradually improving, should accelerate next year. Offshore down a little bit, but not a needle mover. Canada gets better seasonally, production services gets better seasonally, completion gets better with weather and Canrig can't get any worse. So I add all that up, and things should get meaningfully better next quarter. Is that fair?

Yes.

Depends on your definition of meaningfully, but yes.

Yes (multiple speakers). The other thing, Marshall, in your description of offshore, I do think yes, there's the seasonal stuff, but the underlying activity level for the Super Sundowners, for example, and the drilling rigs there seems to have materially been up. So it's not just coming out of that. I think there is some underlying more momentum there.

Right. So up year-over-year, ex the season -- the weather-related stuff, right?

Correct.

Okay, so given all that, up -- the Street defines up meaningfully of $0.20 next quarter. Does that still sound reasonable to you all?

I guess.

I think that's -- where we sit today, that sounds reasonable.

That sounds like a wholehearted, definitely maybe (laughter).

Yes, exactly (laughter).

All right, guys. That was very helpful information on the entire call.

Luke, I think we will wind up the call now.

Okay. Excellent. Ladies and gentlemen, this will conclude your conference call for today. We do thank you for your participation, and this conference will be available for replay. You can access the replay by dialing toll-free 1-877-870-5176 or area code 858-384-5517. Today's access code is 4622815. Again, you can access the toll-free replay system by dialing 1-877-870-5176 or internationally, you can dial area code 858-384-5517. Again, we thank you for your participation, and you may now disconnect your lines.