Nabors Industries Ltd. (NBR) Management Discusses Q2 2013 Results - Earnings Call Transcript

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Nabors Industries Ltd. (NYSE:NBR)

Q2 2013 Earnings Call

July 24, 2013 11:00 am ET


Dennis A. Smith - Director of Corporate Development & Investor Relations

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

Siegfried Meissner - President

Joe M. Hudson - President


James D. Crandell - Cowen and Company, LLC, Research Division

James D. Crandell - Cowen Securities LLC, Research Division

Michael W. Urban - Deutsche Bank AG, Research Division

Robin E. Shoemaker - Citigroup Inc, Research Division

Jason Gilbert - Goldman Sachs Group Inc., Research Division

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division


Ladies and gentlemen, thank you for standing by. Welcome to Nabors Industries Second Quarter 2013 Earnings Conference Call. [Operator Instructions] I’d 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.

Dennis A. Smith

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 and the markets that we work 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’re accessible in 2 ways. If you are participating by webcast, they’re available as a download within the webcast. Alternatively, you can download them from our website at under Investor Relations, then 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 our expectations of future, they are subject to numerous risk factors as elaborated on 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 that -- such forward-looking statements are subject to certain risk and uncertainties as disclosed by Nabors in 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.

Anthony G. Petrello

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 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 these slides by slide number as we proceed.

As you know, we pre-announced our earnings 2 weeks ago as we became aware that on the whole, we would underperform both the Street's and our own expectations. This underperformance was disappointing and was principally driven by the Canrig portion of our other rig services segment, and the U.S. 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 underperformance of these 2 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%, leverage to 2.4x trailing 12-month EBITDA and interest coverage of 7x 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 at 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 15% 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 credit position and are in line with our capital deployment criteria. One example of these capital projects is our PACE-X newbuild program.

Turning to PACE-X performance, we now have 5 PACE-X rigs on revenue: 3 in the Haynesville, 1 in the Marcellus, 1 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 2 rigs, but they are now exceeding expectations. The 3 rigs in the Haynesville Shale have delivered considerable improvement over wells drilled by AC rigs in the same field within the last 6 months. Inclusive of downtime experienced within the intermediate whole section, our PACE-X rigs have reduced average drill time by 26% and the best intermediate whole 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 ROP 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 2 more long-term take-or-pay contracts for newbuild PACE-X rigs. Referring to Slide #5, this brings our total number of PACE-X newbuilds to 21 with 16 of these yet to be deployed.

Next what I'd like to emphasize is that the U.S. 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 U.S. We were recently awarded contracts for 6 upgraded 1,500 horsepower AC rigs in Argentina, 2 upgraded 3,000 horsepower rigs in Northern Iraq, and 1 upgraded 2,000 horsepower rig in Kazakhstan.

Including the 2 newbuild awards, these 11 rigs represent average take-or-pay terms of 3.2 years, they consisted of $150 million in new capital and should generate over $600 million of 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 the 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 view while gradually tightening of rig supply through sustained increases to the 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 newbuilds given recent economics. Once newbuilds become economically viable, we expect that they will pull other renewal rates up with them, much like what happened in the U.S. market starting in 2005.

At this point, today, the undersupply 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 at which any of this is realized is subject to geopolitics, the global macro environment and in some cases, local government procedures or the lack thereof. On the U.S. front, the increased efficiencies of drilling rigs and pressure pumping crews are showing signs of 2 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 U.S. 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, increased 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 50% more stages per day using zipper fracs versus using single-well operations last year. This is just one example, but the combination of pad operations, sliding sleeves, coil fracs 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, we could see a drop-off in 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 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're 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 U.S. drilling market by continuing to differentiate through technologies like the PACE-X rate and operational excellence, as well as by marketing our legacy assets based on a value proposition of safety and efficiency, not just rate; we will focus on rightsizing our cost to our current cash flow; and we’ll continue to work on disposing our E&P and other non-core assets so that we are focusing on efforts that are only core to Nabors.

Let me turn to the financial results, 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 of production services while sequentially better in international offshore were almost entirely offset by declines in Canada and U.S. 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 U.S. 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 rightsize 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 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 largely 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’s 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 underutilized or underpriced 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 3 AC rigs from the U.S.

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 U.S., they can satisfy future international requirements with additional capital for appropriate upgrades.

We have seen an improvement in our U.S. offshore utilization as compared to recent quarters. Our Super Sundowner platform workover 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 imbalance 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 leads to generally higher prices. Our rigs should be particularly effective given that the market supply of similar high-spec rigs is minimal. For example, we are filling a portion of our Argentine award with 2 AC rigs from Colombia and 1 SCR rig that was last operating in Libya.

Now, I’d like to go deeper into these segments. First, U.S. drilling. Our U.S. 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 their 2012 pace.

During the second quarter, in the Lower 48, we added 6 rigs but our average margins for the fleet declined 567 per day which was a number less than what 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 under-utilized vessels back to work and partially due to resiliency in spot market rigs.

Since our rig count bottom in 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 at 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 rates. 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 newbuilds 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 strengths 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 on walking systems that allow multidirectional walking and 30 of which have skid systems. After completion of planned upgrades to walking systems on existing rigs and completion of PACE-X newbuilds, we will have 143 pad-capable rigs, 116 of which will have multidirectional 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 $1,000 per day depending on the region, with the latter seen in Arco Texas in Gulf Coast. Legacy spot rates were in the range $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 a $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-M 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 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 7 to 8 months on rates of $21,000 to $22,000 on average. Six went to the spot market with similar rates and one was stacked. We believe the impact on our margins due to term contracts rolling to lower spot rates 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 predictions of a market reset since the beginning of the year, and we’re equally cautious about a second half rebound. We expect the industry count – rig count to remain flat for the remainder of the year. However, we are focused on making our rig count higher by the end of the year. That said, our optimism remains tempered given efficiencies and budget concerns.

Turning to offshore, the sequential 50% increase in this operation was due to increased utilization, as well as cost reduction resulting from the previously announced organizational consolidation of our U.S. 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 become 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 Alaskan operation posted seasonally lower results as 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 8 rigs that require minimum 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 by characterized by long lead times and will likely not commence for another 2 years or so. It’s important to note that opportunities in Alaska are generally 3x to 4x 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 rigs which account for the majority of our fleet. In the short term, the same spending constraints and outline – and outlook witnessed in the Lower 48 are weighing on the Canadian market. And any positive signs in the U.S. should be reflected positively in Canada.

The Cardium continues to be characterized by an over-supply of smaller rigs putting downward pressure on rates. Operators in the Montney and the Horn River and Fort Liard areas of British Columbia have been slow to release their winter training programs and competition is high among contractors. However, we recently exploited 4 rigs for early phase LNG drilling directed in and around British Columbia. We expect these deep gas fills in B.C. to grow over the next few years as customers begin to ramp up their LNG direct 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 rigs 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’ve said before, we expect this quarter marks the exit from the extended trough that has characterized the international market since 2009.

We expect to see further improvement in third quarter as we see full quarter contribution from Super Sundowner X in Mexico, the startup of one of the recently awarded AC rigs in Argentina, the startup of 2 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 and the mid-2014 startup of the 5 remaining rigs for Argentina and 1 rig for Kazakhstan.

Longer-term approval 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 demand for newbuild rigs. However, these markets can be unpredictable and decisions on tenders are frequently delayed such as the recent 27-rig tender for Saudi, which has been delayed by 2 months so far, which could delay activity by 4 to 6 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 rig services. Combined income from these operations was in line with our expectations. Recall that we normally see a falloff in Alaska base operations in the June quarter as warming weather inhibits operating tempo. These operations account for over 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 drives dropped by more than 50% reflecting lower customer interest in newbuild rigs, as well as the deferral of some shipments.

Canrig’s non-equipment revenue, principally rentals and services, declined by 10% as drilling activity eased. We foresee an uptick in Canrig beginning this quarter supported by sequential increase in top drive shipments and into the future supported by our proprietary automated pipe-handling equipment.

We remain 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 discussion with customers, interest in new projects is high.

Turning to completion and production services, this business line obviously consists of services that complete maintained wells, including pressure pumping, well servicing, workover and coiled tubing rigs and fluids management.

Operating income for this division is tabled out on Slide 16. Completion and Production Services posted 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 for this operation were impacted by the combination of abnormally severe weather in the Bakken and growing pricing pressure, especially in West Texas and to a less extent in South Texas markets. Of Nabors' 18 frac crews currently operating in the U.S., 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, 3 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 frac 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 U.S., and 2 in Canada. Of those 18 in the U.S., 11 are 24-hour crews, and about 50% are working on pads. Given market conditions, we recently added another spread in the U.S. Most of our long-term service agreements have now been reset. We have 8 crews currently working under service agreements which provide some visibility to customer work plans toward the beginning of 2014. The last 2 of the large crew working under legacy term contracts will roll off in Q1 of 2014. As contracts have rolled off, we are largely retaining those relationships and continuing to work for those customers even as we look to add to our customer list.

As for Canada, we have 2 spot crews working in that market which also remains challenging. We are seeing still in the face of these 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 duel fuel capabilities into our frac-ing operations. We also recently closed 4 facilities and continue to review the assets deployed in this business. Our efforts to improve working capital management are paying off with improvements to DSO and days of inventory.

Our efforts to bring efficiencies, to reel 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 underway to continue improvement in our cost structure in this business.

In light of challenging market visibility and spot markets and the continuing industry-wide horsepower supply-demand imbalance, our outlook remains cautious for this business. Apparent efficiency gains in this business and across other service lines have the effect of lowering our customers’ per-well cost while consuming their budgets more quickly than planned. Those pick-ups in efficiency are coming from multiple sources including the zipper fracs I mentioned which increase the number of stages a fleet can pump per day.

These are facilitated by pad drilling which reduces moving time between wells and enables parallel frac-ing operations. Increasing 24-hour operations also expands industry frac-ing capacity. Several customers are already signaling that their 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 U.S. offset by a sharper than expected seasonal drop in Canada. Rig hours in the U.S. increased despite the weather in the Bakken which accounted for about 1/6 of our U.S. well servicing rigs.

As shown on Slide 18, at the end of the second quarter, our U.S. operating fleet consisted of 442 well service rigs, 1,036 fluid service trucks, and almost 3,600 frac 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 and 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 the 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 our flat U.S. drilling market by continuing, as I mentioned, to differentiate ourselves through technology and particularly, through the advances 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 bolted to more 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.

Question-and-Answer Session


[Operator Instructions] Your first question today comes from the line of Jim Crandell of Cowen.

James D. Crandell - Cowen and Company, LLC, Research Division

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 sort of dragging on and on. Maybe you could – and if you could just put some kind of broad number range or timeframe range around the expected sales?

Anthony G. Petrello

We have, as you know, the principal assets left are the E&P assets of the Eagle Ford, Alaska and Horn River. All 3 of those are with packages, with people and being looked at and marketed actively. And as I mentioned, I'm confident you'll see some progress on that very, very shortly. So then the other one that's being marketed is the Peak Logistics operation in Canada. And as well I think that you're going to see some – we are hopeful of seeing some results on that very shortly. So all 4 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 in both markets. The number of players that are in – available in Alaska, participate in Alaska, it's 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 there with Apache and Chevron in that 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.

James D. Crandell - Cowen Securities LLC, Research Division

Okay. On that topic of LNG, Tony, there’s been some talk recently about there potentially being several newbuild 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 do you expect in terms of newbuild announcements in Canada?

Anthony G. Petrello

Well, I think there are inquiries out there on newbuilds and we were – we are looking at them. And so I mentioned we are – we actually just deployed a bunch of assets there that are directed at that. And we understand, principally from the 2 people I just mentioned, there is some large amount of demand for the programs that are consummate up there. So I think that is the case. Question in Canada is the rate structure and the economics because as you all know, the drilling season up there is a short drilling season and the question is to make numbers work on a short drilling season for term contracts. But we are looking at it.

James D. Crandell - Cowen and Company, LLC, Research Division

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 the AC drive rigs? And maybe what has to have to happen or would there be any potential widening of the day rate spread between SCR and AC drive rigs in the marketplace?

Anthony G. Petrello

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’re 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 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 a driver, those rigs are attractive and 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 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 everyone’s focusing on, that Saudi tender doesn’t specify AC rigs.

Siegfried Meissner

And international, in general.

Anthony G. Petrello

And international in general doesn’t specify AC rigs. And so the fact – I mean it’s really remarkable actually that, I mean 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 installed base of a bunch of 2,000 and 3,000 horsepower SCR rigs which can be the platform for tendering to those markets. So and that’s what our focus is, to try to get utilization out of existing assets.


Our next question will come from the line of Mike Urban of Deutsche Bank.

Michael W. Urban - Deutsche Bank AG, Research Division

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 U.S. rigs out or – and potentially even some older rigs out of the U.S. 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?

Anthony G. Petrello

That’s correct. I mean, historically, a lot of in the early days back when international was growing and U.S. was at best sideways, we redeployed a lot of those rigs to the projects particularly in the Middle East. And 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, where the amount of new content becomes so overwhelming and do you want to do that to a base rig that’s old that’s close 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 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 spectrum example.

Siegfried Meissner

And it typically gives an advantage on delivery.

Anthony G. Petrello

Yes. I don’t know if you can hear Siggi but as he said, it also gives us advantage on delivery with some of these international projects where times may matter.

Michael W. Urban - Deutsche Bank AG, Research Division

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

Anthony G. Petrello

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

Michael W. Urban - Deutsche Bank AG, Research Division

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’ve been doing. Do you have anything in the aggregate that would tell us how much you think you’ve saved, how much – maybe how much margin improvement and better yet 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.

Anthony G. Petrello

Well, I think from the – I think as I mentioned in the U.S., I think we’ve taken out about $3 million to $4 million in the overhead in the U.S. operation and we’ve taken about $20 million of overhead in the pressure pumping well services operation. And as I’ve mentioned, that’s just the beginning as far as I’m concerned. We have bunch of initiatives underway to really look at the whole thing. So that’s the 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 an active project right now.

Michael W. Urban - Deutsche Bank AG, Research Division

And I mean would you say you are halfway through that, 3/4 or still in early stages?

Anthony G. Petrello

I’d say we’re in early stage of the – what I just referred to.


Your next question will come from the line of Robin Shoemaker of Citi.

Robin E. Shoemaker - Citigroup Inc, Research Division

I wanted to just ask you if you could give us a little further commentary on your statement about E&P companies overspending their budgets here in the first half of the year and seeing a possible slowdown. Now, most of the year, most of the service companies drillers have kind of called for a flattish rig count through the end of the year. But clearly, last year, if we have a repeat of last year, then we’ll 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?

Anthony G. Petrello

Well, I think the first thing is, as I mentioned, I think that most companies that are over budget are attributing it 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 of payroll. So…

Robin E. Shoemaker - Citigroup Inc, Research Division

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

Anthony G. Petrello

Well, we’re in a business where price is always relevant. But I think people have to look at what – the delivered value of the well. And I think what I was saying with these – particularly with the legacy rigs for 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, I mean, there’s – one of the banks has an analysis of drilling efficiency by region where you see the 4 rigs in the 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 that we’re the leading position. And based on the fourth quarter data that’s available and some – 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 and I think that’s something we can sell.

Robin E. Shoemaker - Citigroup Inc, Research Division

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

Anthony G. Petrello

Well, I think we’ve been successful. As I said, rolling these over at $22,000 and I mean, at between $21,000 and $22,000, and the incremental ones we deploy was at $22,000 and change. And that’s where we think the market is right now.


Your next question will come from the line of Jason Gilbert of Goldman Sachs.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

I was wondering maybe if you put a finer point on Lower 48, land rig supply and demand. You’d mentioned speculative new building by competitors in the press release. And I was wondering how many newbuilds you see out there, industry-wide? And then the follow-up is how much attrition do you expect from the U.S. land fleet over the next couple years?

Anthony G. Petrello


Joe M. Hudson

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

Anthony G. Petrello

Yes, so more to your – to the core of your point there, I mean, I don’t think we have a good handle – no one has 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, was 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.

Joe M. Hudson

When people report them.

Anthony G. Petrello

And the other question is, as operators' plans change, how many current rigs that are on term contracts are going to come kick loose? So, 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 the increments from today, as far as I – I haven’t heard a lot more new building. I mean this one meeting the company talks about continue a cadence of maybe 2 rigs a month, but other than that, I don’t know of anything out there suggesting a lot of new building in this market.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay, that’s helpful. I wasn’t expecting it either but I did see the comment in the press release so I wanted ask. The other question I had is I like the fact that you paid down some debt in the quarter, I mean 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. I was just wondering, what level of leverage do you 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?

Anthony G. Petrello

Well, I think we said, aspirationally and historically being in the mid-20s or high-20s, mid-to-high 20s would sort of get us to the level that we aspire to that historically we’re at, so that’s where we 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 enjoy may in fact be a little bit correlated to the – 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.


Your final question today will come from the line of Marshall Adkins of Raymond James.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

Being the last question, I’ll try to summarize what I thought I heard today and if you would just confirm whether I kind of got it right. U.S. 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?

Anthony G. Petrello


Joe M. Hudson

Depends on your definition of meaningfully…

Anthony G. Petrello

The only other thing, Marshall, in your description of offshore, I do think, yes, there’s the seasonal stuff, but the underlying activity levels for the Super Sundowners, for example, in 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.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

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

Anthony G. Petrello

Correct, correct.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

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

Joe M. Hudson

I guess.

Anthony G. Petrello

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

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

That sounds like a wholehearted definitely maybe.

Anthony G. Petrello

Yes, exactly.

Dennis A. Smith

Luke, I think we'll 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 (858) 384-5517. Today's access code is 4622815. Again, we thank you for your participation, and you may now disconnect your lines.

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