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Section 1: 8-K (8-K)

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 8-K

 

CURRENT REPORT

 

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

Date of Report (Date of earliest event reported) March 28, 2017

 

NABORS INDUSTRIES LTD.

(Exact name of registrant as specified in its charter)

 

Bermuda

 

001-32657

 

98-0363970

(State or Other Jurisdiction of
Incorporation or Organization)

 

(Commission File Number)

 

(I.R.S. Employer
Identification No.)

 

Crown House
4 Par-la-Ville Road
Second Floor
Hamilton, HM08 Bermuda

 

N/A

(Address of principal executive offices)

 

(Zip Code)

 

(441) 292-1510

(Registrant’s telephone number, including area code)

 

N/A

(Former name or former address, if changed since last report.)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

o            Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

o            Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

o            Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 



 

Item 7.01                                           Regulation FD Disclosure.

 

As previously disclosed, on March 28, 2017, Mr. Anthony Petrello, CEO and President of Nabors Industries Ltd. (the “Company”), made a presentation at the Scotia Howard Weil Conference. The script for Mr. Petrello’s presentation is attached hereto as Exhibit 99.1 and incorporated herein by reference.  Mr. Petrello’s script should be read in conjunction with the simultaneously-presented slides, which were previously furnished and which are incorporated into this Form 8-K as Exhibit 99.2.

 

The materials referenced above contain forward-looking statements within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Such forward-looking statements are subject to risks and uncertainties, as disclosed from time to time in the Company’s filings with the Securities and Exchange Commission.  As a result of these factors, actual results may differ materially from those indicated or implied by such forward-looking statements.

 

The information in this Item 7.01 to this Current Report on Form 8-K, including Exhibits 99.1 and 99.2, shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section or Sections 11 and 12(a)(2) of the Securities Act.  This current report on Form 8-K will not be deemed an admission as to the materiality of any information contained herein (including the information incorporated by reference herein).

 

Item 9.01                                           Financial Statements and Exhibits.

 

(d)  Exhibits

 

Exhibit No.

 

Description

 

 

 

99.1

 

Presentation Script

 

 

 

99.2

 

Presentation Slides (incorporated by reference to Exhibit 99.1 of our Form 8-K (File No. 001-32657) filed with the SEC on March 27, 2017)

 

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SIGNATURE

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

 

NABORS INDUSTRIES LTD.

 

 

 

 

 

 

Date: March 28, 2017

By:

/s/ Mark D. Andrews

 

 

Mark D. Andrews

 

 

Corporate Secretary

 

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EXHIBIT INDEX

 

Exhibit No.

 

Description

 

 

 

99.1

 

Presentation Script

 

 

 

99.2

 

Presentation Slides (incorporated by reference to Exhibit 99.1 of our Form 8-K (File No. 001-32657) filed with the SEC on March 27, 2017)

 

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Section 2: EX-99.1 (EX-99.1)

Exhibit 99.1

 

Thank you for that gracious introduction.  I also want to thank all of the staff at Scotia Howard Weil for giving us the opportunity to participate again this year, which I believe is our 26th consecutive year.

 

Today, I would like to focus on two topics:

 

·                  First — a quick operational update, and

·                  Then, commentary on our focus and strategic direction

 

Operational Update

 

First, as you have heard from recent industry updates, US land activity is accelerating sharply. At Nabors, we are experiencing the same dynamic.

 

There is high current demand from customers for our rigs. Consequently, one of our main concerns is ensuring we have sufficient assets to meet that demand.

 

To do this, we have started to dig deeper into our idle rig inventory earlier than we anticipated. This includes moving assets, recertifying

 

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equipment with the associated repairs, and earlier hiring to assist in the somewhat lengthier reactivation process.

 

The longer a rig has been sidelined, the more expensive the repairs required and the more labor needed to bring the rig back to working condition. We are also moving more equipment as we run out of available assets in the fastest growing basins. Finally, we are starting to run out of trained employees to rehire in certain areas, while our training costs are increasing.

 

As a result, we have experienced operational expenses of roughly $500,000 higher per reactivated rig than in the fourth quarter of last year. These costs, when applied to 20 or so rigs reactivated during the quarter, are not insignificant. However, they are one-time costs that we expect to weigh proportionately less on our results, as our working rig fleet continues to expand.

 

In addition, the day rates on our latest contracts continue to increase and now exceed the average day rate on our fleet. Day rates for our

 

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most recent contracts for PACE®-X and PACE®-M rigs are in the $19,000 range. Day rates for new-builds being delivered between 3 and 9 months from today range up to $23,000.

 

We believe that daily margins in the Lower 48, including one-time reactivation costs, will trough in the first quarter and inflect in the second.

 

Turning to international, we also mentioned previously that our client in our largest international market had requested recertification of various structural components, from multiple drilling contractors in the country. This request somewhat impacted our results in the fourth quarter, as we noted in the conference call. At the time, we expected to complete the balance of this process for just over 30 remaining rigs evenly spread over 2017.

 

Since then, our customer has requested that we accelerate the program, and essentially finalize all re-certifications and associated repair work in the first quarter. This has resulted in approximately 20

 

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additional rig re-certifications in the first quarter versus prior expectations. At an average of 20 days per rig required to complete each recertification on 20 extra rigs, the related lost revenue versus initial expectations is also material.

 

I would like to point out, however, that the lost revenue from this program will be essentially the same for the full year. In other words, almost all of the full year impact has been moved into the first quarter. As a result, we expect to put this issue behind us from the second quarter onwards.

 

Strategic Direction

 

Now let me switch topics to our strategy.

 

Since 2012, we have realized approximately $1.6 billion in cash proceeds from non-core asset divestitures.  We consolidated 13 operating entities into three, and five engineering groups into two - yielding large cost savings through standardization.  We also deployed

 

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multiple rigs internationally as well as a new generation of pad-optimal rigs for the US land market.

 

During the recent downturn, we maintained neutral cash flow, reduced net debt by more than $500 million, preserved our dividend and continued to execute on our key R&D initiatives.

 

The one critical strategic objective that we have not commented on in depth until recently was our multiple initiatives toward automation of the drilling rig and processes, which is what we are going to spend our time on today.

 

Interestingly, most of the talk today is about “AC Rigs” and “Pad capable” rigs.  Neither is really new. AC land rigs are 15 year-old technology.  And we have had pad capable rigs on the North Slope in Alaska since 1973.

 

Broadly speaking, new technology in the drilling sector generally originates in deepwater and international markets, and is mainly the domain of the largest service companies.  We assessed the U.S. land

 

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market as technology-starved, and we set out to find those areas where there could be quick wins.  Of course, “quick” is historically a non sequitur in this industry, and even more so in the area of technology.

 

We believe there is a strong business case for redeveloping certain commonplace, but expensive, offshore rig equipment, rig software, and downhole tools for the land market, particularly targeting the US unconventional.  This trend will accelerate due to the desire for factory drilling and to capitalize on the benefits of “Big Data.”  On both of these trends we are still in the second inning of the ballgame.

 

We have focused on those items which can be delivered in a cost-effective and automated fashion.  We believe we have a clear path to our “RIG OF THE FUTURE.”

 

At our analyst meeting this past November, we highlighted a number of technology initiatives. These initiatives - when combined with our other efforts these past several years - create a path for higher levels of free

 

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cash flow and returns on capital employed, even in a moderate US recovery scenario.

 

First — permanent cost reduction.

 

We have achieved a permanent reduction in our cost structure, principally through the efforts I previously mentioned.  Through the downturn, we reduced SG&A by approximately $180 million between the fourth quarters of 2014 and 2016.  While nominal levels of SG&A must increase as the market recovers, we expect to retain the majority of this $180 million savings, directly improving our results.

 

Second - International Portfolio Upside

 

Between 2012 and 2014, we experienced a compounded annual growth rate of 34% in adjusted EBITDA Internationally.  This proved to be relatively resilient throughout the downturn.

 

The intermediate and longer term prospects for growth are promising.  As the international market follows the lead of the Lower 48 market in

 

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technology adoption, our initiatives will create further opportunities.  In Colombia, for example, our PACE®-X rigs have reduced our client’s average days per well by 30%.

 

Our new joint venture with Saudi Aramco will be a significant driver of incremental growth. The JV is committed to deploying a minimum of 50 new AC rigs during the next 10 years.  We were honored that the world’s largest oil producer chose Nabors as its partner in fulfilling their “2030 Vision”.

 

Third — Premium Operational Performance

 

The customer preference for our PACE®-X and more recently our new PACE®-M800/1000 rigs is evidenced by the outsized demand for these rigs.

 

Since the market bottomed 10 months ago, the industry rig count has increased by 110%, whereas our rig count has increased by 154% and our working SmartRig™ by 205%. These gains represent customers’ validation that these rigs are second to none in the industry for high

 

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density pad drilling. The leading-edge pricing for these rigs is now the highest in the industry and increasing.

 

Over the past three years we have worked on improving the “brains” of our rigs and developed our new Rigtelligent™ operating system.  This operating system automates routine drilling procedures.   We believe our pre-programmed recipes can yield further drilling time efficiencies of 20 to 30%.  This is accomplished in two ways:

 

·                  First: performing operations in parallel compared to manual sequential operations.  This reduces what we refer to as hidden flat time.

 

·                  Second: the system consistently performs operations at peak levels compared to the variability of manual operations.

 

Our Rigtelligent™ system is now being expanded to include directional drilling and managed pressure applications, in addition to our well- known Rockit® and Revit™ performance tools, which have been in the market a number of years.

 

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Now let’s see how Rigtelligence™ enables our fourth lever, the integration and automation of auxiliary drilling services.

 

Fourth — Nabors Drilling Solutions

 

A key feature of our Rigtelligent™ operating system is the ability to integrate and automate drilling services traditionally not performed by drilling contractors.  We have developed four categories of services which our operating system accommodates.

 

We believe that these services can be delivered more consistently, reliably and with less manpower than the traditional delivery model of separate providers.

 

We have created a separate operating unit, Nabors Drilling Solutions or NDS, to further develop these services and achieve market penetration.

 

Keep in mind we are not targeting all services around the rig. We are targeting only those services where our technology and our rig footprint provide a unique, scalable and differentiated service offering

 

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through integration with the rig operating system. Let me break this down for you in more detail.

 

The bar chart on this slide [slide 18] illustrates the breakdown of margin per day, per service, we believe NDS can generate by 2020.  The two curves on the right side represent two scenarios of adoption rate and our view of the progression of their contribution to an expected $200 million to $250 million in 2020 EBITDA.

 

If we separate the four categories from the previous slide, the performance drilling tools constitute approximately one quarter of this additional contribution.

 

These products have been proven in the market for several years now.  Although volume has been lower during the downturn, market recognition of the value of these performance-enhancing products has broadened.  This element of NDS is well established with high returns and low capital intensity.

 

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The “Other Services” category at the bottom of the chart consist of BOP testing, choke rental and casing running services.  While pricing remains challenged, all of these services are gaining penetration.   Our available equipment is fully utilized and we are currently building or procuring additional assets.

 

The second largest component of the prospective NDS contribution is Managed Pressure Drilling.  We have started operating MPD in the Lower 48 and are in the process of qualifying the technology in Saudi where we see significant potential.

 

The majority of wells in the US Lower 48 are now drilled utilizing some degree of drilling pressure management.  By controlling the amount of pressure at the bit, we can drill any given formation faster while preventing damage to the wellbore.  Today, standard MPD rig-up and rig-down times are costly for operators and introduce operational and safety risks.  Our MPD hardware and software configuration will bring

 

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significant savings, and when combined with our rig operating system, a superior value proposition for the customer.

 

Our wellbore placement strategy is focused on implementing fully automated closed loop directional drilling.  As spacing between today’s parallel wells has become ever closer, it necessitates a much higher degree of wellbore accuracy to achieve maximum ultimate recovery.

 

We believe the value proposition in automating this service is not solely man-hours reduction. Rather the value proposition is based on consistent, reliable performance through rig automation.

 

Here is an example of how we expect our technology initiative to pay off. Nabors has developed a new proprietary suite of MWD tools. These tools encompass features that do not exist in the majority of MWD tools used today in the U.S. onshore market.

 

In essence, we have taken a deepwater offshore tool and packaged it into a lower cost 30 foot drill collar for land well manufacturing.  The

 

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technical features of the AccuSteer® tool are offered by the big service companies, but at higher operating costs and customer charges.

 

As this chart shows, unlike the typical MWD tools, our Accusteer® tool additionally provides more sophisticated features of downhole dynamics.  For example, shock and vibration, stick slip and pressure at the bit.  This information can be used to mitigate downhole tool and drill bit failures.

 

Perhaps more significantly, with the advent of leveraging big data for drilling optimization, we believe that this information will be of keen interest to operators for developing their own algorithms.

 

Our strategy is perhaps most easily illustrated by a feature incorporated in all our MWD tools—continuous inclination.  This feature continuously measures the vertical inclination of the well as opposed to traditional systems which stop drilling to take a reading and reorient the bit angle every 90 feet.

 

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Let’s take a look at a short 3 minute video that describes the benefits of our Accusteer® tool, particularly continuous inclination.

 

[Viewing of video]

 

Standard Lower 48 tools can lead to significant inaccuracies in today’s laterals, both in terms of calculating true vertical depth and maintaining target in the horizontal.  The ability of AccuSteer® to feed wellbore inclination to the surface continuously addresses both problems.

 

Knowing the true vertical depth for your kickoff point and staying in the zone is critical when your pay targets can be 30 to 40 feet.  Recently, an operator found it was missing the horizontal section of his reservoir due to the inherent inaccuracy of using 90 foot data and the corresponding inability to accurately determine the true vertical depth where the curve should have begun.  Subsequent wells with Accusteer® revealed that they had previously missed 200 feet of reservoir before they got back on the correct path.

 

In another case using AccuSteer®, we helped a major US Operator stay within a one foot thick easily-drilled strata, within a 30 foot horizontal reservoir, for over 4,000 feet without stopping to take extra surveys

 

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and without sliding for a corresponding course correction. The result was a wellbore placed 100% within the target.

 

The more comprehensive data produced by our AccuSteer® MWD tool seamlessly integrates with our new Rigwatch® Navigator™ software.  This software automates the calculation for the driller to stay on the planned wellbore path.  It automatically determines whether to rotate, or to stop and reorient.  It also calculates the distance to drill and the angle to get back on the correct path.  All of these calculations today are done manually by the directional driller.

 

This unique capability has delivered directional drilling jobs with remote monitoring assistance and in a few cases operated remotely from our Rigline 24/7™ control room.  We expect the process to soon outperform the current standards of a directional driller.

 

Again, our mission in wellbore placement, is not to duplicate or bundle standard directional drilling services.  Instead, we seek to deliver through the use of rig automation a superior and consistent service to the operator.

 

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Like more sophisticated MWD tools, rotary steerable tools have not played a large role in the US land market — again historically largely for cost reasons.  As the need for improved geosteering becomes dominant, its use is increasing.

 

Approximately two years ago we acquired a Norwegian startup developing an innovative new concept for a rotary steerable tool.  Our objective was simple: A reliable, cost efficient, tool that would work well in the evolving US land market, much like our AccuSteer® strategy.

 

The prototype units have been in field testing mode for two quarters and have met the design criteria.  Specifically, it can build angle at a rate of 15° per hundred feet of wellbore, which matches the best in class RSS tools.

 

We believe our tool will have broad applicability, not just in the Lower 48 market, but in key international markets as well.  We expect commerciality by the end of the year.  Even modest penetration of this service on our rigs would have a very substantial effect on margins.

 

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Fifth — the iRig® System — Full drill floor and downhole automation

 

The fifth and final lever of our strategy is the achievement of a man-less rig floor.  When combined with automatic control of downhole directional drilling, there will be a fully automated factory drilling process.  We name this fully automated rig: the iRig®.

 

A man-less rig floor, automating drill pipe handling and casing running functions, has been an elusive aspiration of our industry for a long time.  While expensive deepwater rigs have had similar features, there are many challenges to designing such a system for land rigs.

 

A land system must be compact, relatively low cost to build and operate, readily portable, sufficiently rugged to withstand frequent rig ups and rig downs, and survive frequent transport.

 

At our recent analyst day, we showed a working prototype of our new iRacker™ system which addresses these goals.  We are finishing prototype testing and completing production drawings.  We expect to

 

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have the first units with customers on rigs in field trials in the second half of this year.

 

Perhaps most significant is that we will not need to build all new rigs—like some others — to achieve this level of true factory automation. Because we have been working in parallel on this initiative when developing our SmartRig™ system, we expect that all our SmartRig™ systems will be easily upgraded at modest cost for these features.  This gives us the potential of having 100 fully automated rigs within a much earlier time frame compared to newbuilds.

 

The bottom line of all this effort is to restore our cash flow generation and earnings power to historical highs, even in the face of a US land drilling industry that is continually more efficient and less rig intensive per BOE produced.  This table lays out the parameters that get us to $1.6 billion in adjusted EBITDA in 2020, which equals our 2014 high.

 

While this chart shows average margins and rig counts for our global fleet, it is important to point out that this is achievable in a US land rig

 

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count of 1200 rigs compared to the 1875 rigs working in 2014.  For Nabors, this means a US land rig count approximately 2/3 of our 2014 high and 2/3 of our average US rig margins when adjusted for the mix shift to a higher proportion of high specification rigs.

 

Internationally, rig activity and margins are not heroic either.  They are essentially equal to the rig count and margins we achieved in early 2016.

 

The incremental contribution of the portfolio of NDS services is a significant component in achieving these results.  Today, we have one or more services on approximately 150 rigs and are steadily increasing this penetration, primarily in the North American market.  Internationally, we are pursuing multiple opportunities.

 

By pursuing this strategy, we expect our adjusted EBITDA growth to generate sufficient free cash flow to reduce net debt to less than one-and-a-half times adjusted 2020 EBITDA compared to today’s level of

 

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just over 5.  Similarly, we expect to restore our returns on capital employed to an attractive spread to our cost of capital.

 

We believe that Operators’ quest for more efficiency is here to stay. The genie is out of the bottle. Interest in automated drilling and integrating drilling data for optimization will only accelerate and those trends will be core to the drilling landscape.  In the future, we have a plan, and now solutions, to meet those challenges.

 

Thank you for your time and attention today.

 

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