NABORS INDUSTRIES LTD
10-Ks and 10-Qs
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Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
| (Mark One) | ||
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the fiscal year ended December 31, 2010 | ||
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to |
Commission File Number
001-32657
NABORS INDUSTRIES
LTD.
(Exact name of registrant as
specified in its charter)
| Bermuda | 980363970 | |
|
(State or Other Jurisdiction
of
Incorporation or Organization ) |
(I.R.S. Employer
Identification No .) |
|
|
Mintflower Place
8 Par-La-Ville Road Hamilton, HM08 Bermuda (Address of principal executive offices ) |
N/A
(Zip Code ) |
(441) 292-1510
(Registrant’s telephone
number, including area
code
)
Securities registered pursuant to Section 12(b) of the
Securities Exchange Act of 1934:
| Title of Each Class | Name of Each Exchange on Which Registered | |
|
Common shares, $.001 par value per share
|
The New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the
Securities Exchange Act of 1934:
None.
None.
Indicate by check mark whether the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. YES
þ
NO
o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. YES
o
NO
þ
Indicate by check mark whether the registrant: (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past
90 days. YES
þ
NO
o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding
12 months. YES
þ
NO
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act. (Check one):
|
Large accelerated filer
þ
|
Accelerated filer o |
Non-accelerated filer
o
(Do not check if a smaller reporting company) |
Smaller Reporting company o |
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). YES
o
NO
þ
The aggregate market value of the 192,800,936 common shares, par
value $.001 per share, held by non-affiliates of the registrant,
based upon the closing price of our common shares as of the last
business day of our most recently completed second fiscal
quarter, June 30, 2010, of $17.62 per share as reported on
the New York Stock Exchange, was $3,397,152,492. Common shares
held by each officer and director and by each person who owns 5%
or more of the outstanding common shares have been excluded in
that such persons may be deemed affiliates. This determination
of affiliate status is not necessarily a conclusive
determination for other purposes.
The number of common shares, par value $.001 per share,
outstanding as of February 24, 2011 was 286,145,675.
DOCUMENTS
INCORPORATED BY REFERENCE (to the extent indicated
herein)
Specified
portions of the definitive Proxy
Statement to be distributed in connection with our 2011 annual meeting of shareholders (Part III).
Statement to be distributed in connection with our 2011 annual meeting of shareholders (Part III).
NABORS
INDUSTRIES LTD.
Form 10-K Annual Report
For the Year Ended December 31, 2010
Table of Contents
Form 10-K Annual Report
For the Year Ended December 31, 2010
Table of Contents
2
Table of Contents
Our internet address is
www.nabors.com
. We make available
free of charge through our website our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended (the “Exchange Act”), as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the Securities and Exchange
Commission (the “SEC”). In addition, a glossary of
drilling terms used in this document and documents relating to
our corporate governance (such as committee charters, governance
guidelines and other internal policies) can be found on our
website. The SEC maintains an internet site (
www.sec.gov
)
that contains reports, proxy and information statements and
other information regarding issuers that file electronically
with the SEC.
FORWARD-LOOKING
STATEMENTS
We often discuss expectations regarding our future markets,
demand for our products and services, and our performance in our
annual and quarterly reports, press releases, and other written
and oral statements. Statements relating to matters that are not
historical facts are “forward-looking statements”
within the meaning of the safe harbor provisions of
Section 27A of the Securities Act of 1933, as amended (the
“Securities Act”), and Section 21E of the
Exchange Act. These “forward-looking statements” are
based on an analysis of currently available competitive,
financial and economic data and our operating plans. They are
inherently uncertain and investors should recognize that events
and actual results could turn out to be significantly different
from our expectations. By way of illustration, when used in this
document, words such as “anticipate,”
“believe,” “expect,” “plan,”
“intend,” “estimate,” “project,”
“will,” “should,” “could,”
“may,” “predict” and similar expressions are
intended to identify forward-looking statements.
You should consider the following key factors when evaluating
these forward-looking statements:
| • | fluctuations in worldwide prices of and demand for natural gas and oil; | |
| • | fluctuations in levels of natural gas and oil exploration and development activities; | |
| • | fluctuations in the demand for our services; | |
| • | the existence of competitors, technological changes and developments in the oilfield services industry; | |
| • | the existence of operating risks inherent in the oilfield services industry; | |
| • | the possibility of changes in tax and other laws and regulations; | |
| • | the possibility of political instability, war or acts of terrorism in any of the countries where we operate; and | |
| • | general economic conditions including the capital and credit markets. |
Our businesses depend to a large degree on the level of spending
by oil and gas companies for exploration, development and
production activities. Therefore, a sustained increase or
decrease in the price of natural gas or oil that has a material
impact on exploration, development or production activities
could also materially affect our financial position, results of
operations and cash flows.
The above description of risks and uncertainties is by no means
all-inclusive, but is designed to highlight what we believe are
important factors to consider. For a more detailed description
of risk factors, please refer to Part I,
Item 1A. —
Risk Factors.
Unless the context requires otherwise, references in this report
to “we,” “us,” “our,” “the
Company,” or “Nabors” mean Nabors Industries Ltd.
and, where the context requires, includes our subsidiaries. Our
subsidiaries include Nabors Industries, Inc., a Delaware
corporation (“Nabors Delaware”).
3
Table of Contents
| ITEM 1. | BUSINESS |
Introduction
Nabors is the largest land drilling contractor in the world and
one of the largest land well-servicing and workover contractors
in the United States and Canada:
| • | We actively market approximately 550 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. | |
| • | We actively market approximately 555 rigs for land well-servicing and workover work in the United States and approximately 172 rigs for land well-servicing and workover work in Canada. |
We are also a leading provider of offshore platform workover and
drilling rigs, and actively market 37 platform, 13
jack-up
and
three barge rigs in the United States, including the Gulf of
Mexico, and multiple international markets.
In addition to the foregoing services:
| • | We offer a wide range of ancillary well-site services, including hydraulic fracturing, engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select United States and international markets. | |
| • | We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software. | |
| • | We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests. | |
| • | We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets nine rigs in addition to the rigs we lease to the joint venture. | |
| • | We also provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft. |
During the third quarter of 2010, we acquired through a tender
offer and merger transaction (the “Superior Merger”),
all of the outstanding common stock of Superior Well Services,
Inc. (“Superior”). Superior provides a wide range of
wellsite solutions to oil and natural gas companies, consisting
primarily of technical pumping services, including hydraulic
fracturing, a process sometimes used in the completion of oil
and gas wells whereby water, sand and chemicals are injected
under pressure into subsurface formations to stimulate gas and,
to a lesser extent, oil production, and down-hole surveying
services. The effects of the Superior Merger and the operating
results of Superior from the acquisition date to
December 31, 2010 are included in the accompanying audited
consolidated financial statements and are reflected in our
operating segment, titled “Pressure Pumping.” See
Note 7 — Acquisitions and Divestitures in
Part II, Item 8. — Financial Statements and
Supplementary Data for additional information.
Nabors was formed as a Bermuda exempt company on
December 11, 2001. Through predecessors and acquired
entities, Nabors has been continuously operating in the drilling
sector since the early 1900s. Our principal executive offices
are located at Mintflower Place, 8 Par-La-Ville Road,
Hamilton, HM08, Bermuda, and our phone number there is
(441) 292-1510.
Our Fleet
of Rigs
| • | Land Rigs. A land-based drilling rig generally consists of engines, a drawworks, a mast (or derrick), pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string and |
4
Table of Contents
| related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill string, causing the drill bit to bore through the subsurface rock layers. Rock cuttings are carried to the surface by the circulating drilling fluid. The intended well depth, bore hole diameter and drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. |
Special-purpose drilling rigs used to perform workover services
consist of a mobile carrier, which includes an engine, drawworks
and a mast, together with other standard drilling accessories
and specialized equipment for servicing wells. These rigs are
specially designed for major repairs and modifications of oil
and gas wells, including standard drilling functions. A
well-servicing rig is specially designed for periodic
maintenance of oil and gas wells for which service is required
to maximize the productive life of the wells. The primary
function of a well-servicing rig is to act as a hoist so that
pipe, sucker rods and down-hole equipment can be run into and
out of a well, although they also can perform standard drilling
functions. Because of size and cost considerations, these
specially designed rigs are used for these operations rather
than the larger drilling rigs typically used for the initial
drilling job.
Land-based drilling rigs are moved between well sites and
between geographic areas of operations using our fleet of
cranes, loaders and transport vehicles or those of third-party
service providers. Well-servicing rigs are typically
self-propelled, while heavier capacity workover rigs are either
self-propelled or trailer-mounted and include auxiliary
equipment, which is either transported on trailers or moved with
trucks.
| • | Platform Rigs. Platform rigs provide offshore workover, drilling and re-entry services. Our platform rigs have drilling and/or well-servicing or workover equipment and machinery arranged in modular packages that are transported to, and assembled and installed on, fixed offshore platforms owned by the customer. Fixed offshore platforms are steel tower-like structures that either stand on the ocean floor or are moored floating structures. The top portion, or platform, sits above the water level and provides the foundation upon which the platform rig is placed. | |
| • | Jack-up Rigs. Jack-up rigs are mobile, self-elevating drilling and workover platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the hull, which contains the drilling and/or workover equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. The rig legs may operate independently or have a mat attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas. Many of our jack-up rigs are of cantilever design — a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over adjacent, fixed platforms. Nabors’ shallow workover jack-up rigs generally are subject to a maximum water depth of approximately 125 feet, while some of our jack-up rigs may drill in water depths as shallow as 13 feet. Nabors also has deeper water jack-up rigs that are capable of drilling at depths between eight feet and 150 to 250 feet. The water depth limit of a particular rig is determined by the length of its legs and by the operating environment. Moving a rig from one drill site to another involves lowering the hull down into the water until it is afloat and then jacking up its legs with the hull floating. The rig is then towed to the new drilling site. | |
| • | Inland Barge Rigs. One of Nabors’ barge rigs is a full-size drilling unit. We also own two workover inland barge rigs. These barges are designed to perform plugging and abandonment, well-service or workover services in shallow inland, coastal or offshore waters. Our barge rigs can operate at depths between three and 20 feet. |
Additional information regarding the geographic markets in which
we operate and our business segments can be found in
Note 22 — Segment Information in Part II,
Item 8. — Financial Statements and Supplementary
Data.
5
Table of Contents
Customers:
Types of Drilling Contracts
Our customers include major oil and gas companies, national oil
and gas companies and independent oil and gas companies. No
customer accounted for more than 10% of our consolidated
revenues in 2010 or 2009.
On land in the U.S. Lower 48 states and Canada, we
typically enter into contracts with durations ranging from one
to three years. Under these contracts, our rigs are committed to
one customer over that term. Most of our recent contracts for
newly constructed rigs have three-year terms. Contracts relating
to offshore drilling and land drilling in Alaska and
international markets generally provide for longer terms,
usually from one to five years. Offshore workover projects are
often contracted on a single-well basis. We generally are
awarded drilling contracts through competitive bidding, although
we occasionally enter into contracts by direct negotiation. Most
of our single-well contracts are subject to termination by the
customer on short notice, but some can be firm for a number of
wells or a period of time, and may provide for early termination
compensation in certain circumstances. Contract terms and rates
differ depending on a variety of factors, including competitive
conditions, the geographical area, the geological formation to
be drilled, the equipment and services to be supplied, the
on-site
drilling conditions and the anticipated duration of the work to
be performed.
In recent years, all of our drilling contracts have been daywork
contracts. A daywork contract generally provides for a basic
rate per day when drilling (the dayrate for our providing a rig
and crew) and for lower rates when the rig is moving, or when
drilling operations are interrupted or restricted by equipment
breakdowns, adverse weather conditions or other conditions
beyond our control. In addition, daywork contracts may provide
for a lump-sum fee for the mobilization and demobilization of
the rig, which in most cases approximates our incurred costs. A
daywork contract differs from a footage contract (in which the
drilling contractor is paid on the basis of a rate per foot
drilled) and a turnkey contract (in which the drilling
contractor is paid for drilling a well to a specified depth for
a fixed price).
Well-servicing
and Workover Services
Although some wells in the United States flow oil to the surface
without mechanical assistance, most are in mature production
areas that require pumping or some other form of artificial
lift. Pumping oil wells characteristically require more
maintenance than flowing wells because of the operation of the
mechanical pumping equipment.
| • | Well-servicing/Maintenance Services. We provide maintenance services on the mechanical apparatus used to pump or lift oil from producing wells. These services include, among other activities, repairing and replacing pumps, sucker rods and tubing. They also occasionally include drilling services. We provide the rigs, equipment and crews for these tasks, which are performed on both oil and natural gas wells, but which are more commonly required on oil wells. Maintenance services typically take less than 48 hours to complete. Rigs generally are provided to customers on a call-out basis. We are paid an hourly rate and work typically is performed five days a week during daylight hours. | |
| • | Workover Services. Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects. Workovers normally are carried out with a rig that includes standard drilling accessories such as rotary drilling equipment, mud pumps, mud tanks and blowout preventers plus other specialized equipment for servicing rigs. A workover may last anywhere from a few days to several weeks. We are paid a daily rate and work is generally performed seven days a week, 24 hours a day. | |
| • | Completion Services. The kinds of activities necessary to carry out a workover operation are essentially the same as those required to “complete” a well when it is first drilled. The completion process may involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may |
6
Table of Contents
| take a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day. |
| • | Production and Other Specialized Services. We also can provide other specialized services, including onsite temporary fluid storage; the supply, removal and disposal of specialized fluids used during certain completion and workover operations; and the removal and disposal of salt water that often accompanies the production of oil and natural gas. We also provide plugging services for wells from which the oil and natural gas has been depleted or further production has become uneconomical. We are paid an hourly or a per-unit rate, as applicable, for these services. |
Pressure
Pumping Services
In connection with the Superior Merger, we conduct technical and
fluid logistics services. Technical services include technical
pumping services, completion, production and rental tool
services and down-hole surveying services. Fluid logistics
services include those services related to the transportation,
storage and disposal of fluids that are used in the drilling,
development and production of hydrocarbons. During the period
September 10, 2010 through December 31, 2010,
approximately 5.5% of revenues from our Pressure Pumping
operating segment came from an unconsolidated Nabors affiliate.
Our proportionate share of any profits resulting from sales to
this affiliate were eliminated in consolidation.
Oil and
Gas Investments
In our Oil and Gas operating segment, we invest in oil and gas
exploration, development and production operations in the United
States, Canada and Colombia. In addition, in 2006, we entered
into an agreement with First Reserve Corporation to form select
joint ventures to invest in oil and gas exploration
opportunities worldwide. During 2007, three joint ventures were
formed for operations in the United States, Canada and Colombia.
We hold a 50% ownership interest in the Canadian entity, Stone
Mountain Venture Partnership (“SMVP”) and 49.7%
ownership interests in the U.S. and Colombia entities, NFR
Energy LLC (“NFR Energy”) and Remora Energy
International LP (“Remora”), respectively. We account
for these investments using the equity method of accounting.
Each joint venture pursues development and exploration projects
with both existing Nabors customers and other operators in a
variety of forms, including operated and non-operated working
interests, joint ventures, farm-outs and acquisitions. Our Oil
and Gas operating segment includes both wholly owned and
joint-venture operations and focuses on the exploration for and
the acquisition, development and production of natural gas, oil
and natural gas liquids in Alaska, Arkansas, Louisiana,
Oklahoma, Mississippi, Montana, North Dakota, Texas, Utah and
Wyoming. Outside of the United States, we and our joint ventures
own or have interests in the Canadian provinces of Alberta and
British Columbia and in Colombia.
During 2010, we began actively marketing some of our oil and gas
assets in Canada and Colombia, including our ownership interests
in SMVP and Remora. Additional information about recent
activities for this segment can be found in Part II,
Item 7. — Management’s Discussion and
Analysis of Financial Condition and Results of Operations as
well as Part II, Item 8. — Financial
Statements and Supplementary Data —
Note 21 — Discontinued Operations.
Other
Services
Canrig Drilling Technology Ltd., our drilling technologies and
well services subsidiary, manufactures top drives, which are
installed on both onshore and offshore drilling rigs. We market
our top drives throughout the world. We rent top drives and
catwalks, and provide installation, repair and maintenance
services to our customers. We also offer rig instrumentation
equipment, including proprietary
RIGWATCH
tm
software and computerized equipment that monitors a rig’s
real-time performance. Our directional drilling system,
ROCKIT
tm
,
is experiencing high growth in the marketplace. In addition, we
specialize in daily reporting software for drilling operations,
making this data available through the internet. We also provide
mudlogging services. Canrig Drilling Technology Canada Ltd., one
of our Canadian subsidiaries, manufactures catwalks
7
Table of Contents
which are installed on both onshore and offshore drilling rigs.
Ryan Energy Technologies, Inc., another one of our subsidiaries,
manufactures and sells directional drilling and rig
instrumentation equipment and provides data collection services
to oil and gas exploration and service companies. Nabors has a
50% ownership interest in Peak Oilfield Service Company, a
general partnership with a subsidiary of Cook Inlet Region,
Inc., a leading Alaskan native corporation. Peak Oilfield
Service Company provides heavy equipment to move drilling rigs,
water, other fluids and construction materials, primarily on
Alaska’s North Slope and in the Cook Inlet region. The
partnership also provides construction and maintenance for ice
roads, pads, facilities, equipment, drill sites and pipelines.
Nabors also has a 50% membership interest in Alaska Interstate
Construction, L.L.C., a general contractor involved in the
construction of roads, bridges, dams, drill sites and other
facility sites, as well as the provision of mining support in
Alaska; the other member of Alaska Interstate Construction,
L.L.C. is a subsidiary of Cook Inlet Region, Inc. Revenues are
derived from services to companies engaged in mining and public
works. Nabors Blue Sky Ltd. leases aircraft used for logistics
services for onshore drilling in Canada using helicopters and
fixed-wing aircraft.
Our
Employees
As of December 31, 2010, Nabors employed approximately
23,412 persons, of whom approximately 2,892 were employed
by unconsolidated affiliates. We believe our relationship with
our employees is generally good.
Some rig employees in Argentina and Australia are represented by
collective bargaining units.
Seasonality
Our Canada and Alaska drilling and workover operations are
subject to seasonal variations as a result of weather conditions
and generally experience reduced levels of activity and
financial results during the second quarter of each year. In
addition, our pressure pumping operations located in the
Appalachian, Mid-Continent, and Rocky Mountain regions of the
United States can be adversely affected by seasonal weather
conditions, primarily in the spring, as many municipalities
impose weight restrictions on the paved roads that lead to our
jobsites due to the muddy conditions caused by spring thaws.
Global warming could lengthen these periods of reduced activity,
but we cannot currently estimate to what degree. Our overall
financial results reflect the seasonal variations experienced in
these operations. Seasonality does not materially impact the
remaining portions of our business.
Research
and Development
Research and development constitutes a growing part of our
overall business. The effective use of technology is critical to
maintaining our competitive position within the drilling
industry. We expect to continue developing technology internally
and acquiring technology through strategic acquisitions.
Industry/Competitive
Conditions
To a large degree, Nabors’ businesses depend on the level
of capital spending by oil and gas companies for exploration,
development and production activities. A sustained increase or
decrease in the price of natural gas or oil could have a
material impact on the exploration, development and production
activities of our customers and could materially affect our
financial position, results of operations and cash flows. See
Part I, Item 1A. — Risk Factors —
Fluctuations in oil and natural gas prices could adversely
affect drilling activity and our revenues, cash flows and
profitability
.
Our industry remains competitive. The number of available rigs
exceeds demand in many of our markets, resulting in strong price
competition. Many rigs can be readily moved from one region to
another in response to changes in levels of activity, which may
result in an oversupply of rigs in such areas. Many of the total
available contracts are currently awarded on a bid basis, which
further increases competition based on price. The land drilling,
workover and well-servicing market is generally more competitive
than the offshore market due to the larger number of rigs and
market participants.
8
Table of Contents
From 2005 through most of 2008, demand was strong for drilling
services driven by a sustained increase in the level of
commodity prices; supply of and demand for land drilling
services were largely in balance in the United States and other
markets, with demand actually exceeding supply in some of our
markets. This resulted in an increase in rates being charged for
rigs across our North American, Offshore and International
markets. In late 2008, falling oil prices and the declines in
natural gas prices forced a curtailment of drilling-related
expenditures by many companies and resulted in an oversupply of
rigs in the markets where we operate. During 2009 and the first
half of 2010, this continued decline in drilling and related
activity impacted our key markets.
In all of our geographic markets, we believe price and the
availability and condition of equipment are the most significant
factors in determining which drilling contractor is awarded a
job. Other factors include the availability of trained personnel
possessing the required specialized skills; the overall quality
of service and safety record; and the ability to offer ancillary
services. Increasingly, the ability to deliver rigs with new
technology and features is becoming a competitive factor. In
international markets, experience in operating in certain
environments, as well as customer alliances, have been factors
in the selection of Nabors.
Certain competitors are present in more than one of Nabors’
operating regions, although no one competitor operates in all of
these areas. In the U.S. Lower 48 states, we compete
with Helmerich and Payne, Inc. and Patterson-UTI Energy, Inc.,
and several hundred other competitors with national, regional or
local rig operations. In our U.S. Land Well-servicing
operating segment, we compete with Basic Energy Services, Inc.,
Key Energy Services, Inc., Complete Energy Services and numerous
other competitors having smaller regional or local rig
operations. In Canada and U.S. Offshore, we compete with
many firms of varying size, several of which have more
significant operations in those areas than Nabors. Elsewhere, we
compete directly with various contractors at each location where
we operate. Our Pressure Pumping operating segment competes with
small and mid-sized independent contractors, as well as major
oilfield services companies with operations outside of the
United States. We believe that the market for land drilling,
well-servicing and workover and pressure pumping contracts will
continue to be competitive for the foreseeable future.
Our other operating segments represent a relatively smaller part
of our business, and we have numerous competitors in each area.
Our Canrig Drilling Technology Ltd. subsidiary is one of the
three major manufacturers of top drives. Its largest competitors
in that market are National Oilwell Varco and Tesco. Its largest
competitors in the manufacture of rig instrumentation systems
are Pason and National Oilwell Varco’s Totco subsidiary.
Mudlogging services are provided by a number of entities that
serve the oil and gas industry on a regional basis. In the
U.S. Lower 48 states, there are hundreds of rig
transportation companies in each of our operating regions. In
Alaska, Peak Oilfield Service principally competes with Alaska
Petroleum Contractors for road, pad and pipeline maintenance,
and is one of many drill site and road construction companies,
the largest of which is VECO Corporation, and Alaska Interstate
Construction principally competes with large general
contractors, including Granite Construction Company and Quality
Asphalt Paving on public works projects and Alaska Frontier
Constructors and CH2MHill on resource development projects.
Our
Business Strategy
Since 1987, with the installation of our current management
team, we have adhered to a consistent strategy aimed at
positioning Nabors to grow and prosper in times of good market
conditions and to mitigate adverse effects during periods of
poor market conditions. We have maintained a financial posture
that allows us to capitalize on market weakness and strength by
adding to our business base, thereby enhancing our upside
potential. The principal elements of our strategy have been to:
| • | Maintain flexibility to respond to changing conditions. | |
| • | Maintain a conservative and flexible balance sheet. | |
| • | Build a base of premium assets cost effectively. | |
| • | Establish and maintain low operating costs through economies of scale. | |
| • | Develop and maintain long-term, mutually attractive relationships with key customers and vendors. |
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| • | Build a diverse business in long-term, sustainable and worthwhile geographic markets. | |
| • | Recognize and seize opportunities as they arise. | |
| • | Continually improve safety, quality and efficiency. | |
| • | Implement leading-edge technology where cost effective to do so. | |
| • | Increase shareholder value by expanding our oil and gas reserves and production. |
We have designed our business strategy to allow us to grow and
remain profitable in any market environment. The major
developments in our business in recent years illustrate our
implementation of this strategy and its continuing success.
Beginning in 2005, we took advantage of the robust rig market in
the United States and elsewhere to obtain a high volume of
contracts for newly constructed rigs. A large portion of these
rigs are subject to long-term contracts with creditworthy
customers with the most significant impact occurring in our
International operations. This will not only expand our
operations with the latest
state-of-the-art
rigs, which should better weather downturns in market activity,
but eventually replace the oldest and least capable rigs in our
existing fleet. However, this positive trend in the rig market
slowed in the fourth quarter of 2008 and throughout 2009 and the
first half of 2010, due to the continued steady decline in
natural gas and oil prices. As a result of lower commodity
prices, many of our customers’ drilling programs were
reduced and the demand for additional rigs was substantially
reduced. In the latter half of 2010, commodity prices
strengthened and our drilling activity improved. Although we
expect market conditions to remain challenging during 2011, we
believe the deployment of our newer and higher-margin rigs under
long-term contracts will enhance our competitive position when
market conditions improve.
Acquisitions
and Divestitures
We have grown from a land drilling business centered in the
U.S. Lower 48 states, Canada and Alaska to an
international business with operations on land and offshore in
many of the major oil and gas markets in the world. At the
beginning of 1990, our fleet consisted of 44 actively marketed
land drilling rigs in Canada, Alaska and in various
international markets. Today, our worldwide fleet of actively
marketed rigs consists of over 550 land drilling rigs, more
than 700 rigs for land well-servicing and workover work in the
United States and Canada, offshore platform rigs,
jack-up
units, barge rigs and a large component of trucks and fluid
hauling vehicles. This growth was fueled in part by strategic
acquisitions. Although Nabors continues to examine
opportunities, there can be no assurance that attractive rigs or
other acquisition opportunities will continue to be available,
that the pricing will be economical or that we will be
successful in making such acquisitions in the future.
On January 3, 2006, we completed an acquisition of 1183011
Alberta Ltd., a wholly owned subsidiary of Airborne Energy
Solutions Ltd., through the purchase of all common shares
outstanding for cash for a total purchase price of
Cdn.$41.7 million (U.S. $35.8 million). In
addition, we assumed debt, net of working capital, totaling
approximately Cdn.$10.0 million
(U.S. $8.6 million). On that date, Nabors Blue Sky
Ltd. (formerly 1183011 Alberta Ltd.) owned 42 helicopters and
fixed-wing aircraft and owned and operated a fleet of
heliportable well-service equipment. The purchase price was
allocated based on final valuations of the fair value of assets
acquired and liabilities assumed as of the acquisition date and
resulted in goodwill of approximately
U.S. $18.8 million. During 2008 and 2009, the results
of our impairment tests of goodwill and intangible assets
indicated a permanent impairment to goodwill and to an
intangible asset of Nabors Blue Sky Ltd. As such, the goodwill
has been fully impaired as of December 31, 2009.
On May 31, 2006, we completed an acquisition of Pragma
Drilling Equipment Ltd.’s business, which manufactures
catwalks, iron roughnecks and other related oilfield equipment,
through an asset purchase consisting primarily of intellectual
property for a total purchase price of Cdn.$46.1 million
(U.S. $41.5 million). The purchase price has been
allocated based on final valuations of the fair market value of
assets acquired and liabilities assumed as of the acquisition
date and resulted in goodwill of approximately
U.S. $10.5 million.
On August 8, 2007, we sold our Sea Mar business which had
previously been included in Other Operating Segments. The assets
included 20 offshore supply vessels and related assets,
including a right under a vessel
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construction contract. The operating results of this business
for years ended December 31, 2007 and before are accounted
for as discontinued operations.
On September 10, 2010, we completed the Superior Merger at
a cash purchase price of $22.12 per share, or approximately
$681.3 million in the aggregate. The purchase price was
allocated to the net tangible and intangible assets acquired and
liabilities assumed based on their fair value at the acquisition
date. The excess of the purchase price over such fair values was
$335.0 million and was recorded as goodwill. Superior
provides a wide range of wellsite solutions to oil and natural
gas companies, primarily technical pumping services and
down-hole surveying services. The effects of the Superior Merger
and the operating results from the acquisition date to
December 31, 2010 are reflected in the accompanying audited
consolidated financial statements. Additional information about
Superior can be found in Part II, Item 7. —
Management’s Discussion and Analysis of Financial Condition
and Results of Operations as well as Part II,
Item 8. — Financial Statements and Supplementary
Data — Note 7 — Acquisitions and
Divestitures.
On December 31, 2010, we purchased the business of Energy
Contractors LLC (“Energy Contractors”) for a total
cash purchase price of $53.4 million. The assets were
comprised of vehicles and rig equipment and are included in our
U.S. Land Well-servicing operating segment. The purchase
price was allocated to the net tangible and intangible assets
acquired based on their preliminary fair value estimates as of
December 31, 2010. The excess of the purchase price over
the fair value of the assets acquired was recorded as goodwill
in the amount of $5 million.
From time to time, we may sell a subsidiary or group of assets
outside of our core markets or business if it is economically
advantageous for us to do so. During 2010, we began actively
marketing our oil and gas assets in the Horn River basin in
Canada and in the Llanos basin in Colombia. These assets include
our 49.7% and 50.0% ownership interests in our investments of
Remora and SMVP, respectively, which we account for using the
equity method of accounting. All of these assets are included in
our Oil and Gas operating segment. We determined that the plan
of sale criteria in the ASC Topic relating to the Presentation
of Financial Statements for Assets Sold or Held for Sale had
been met during the third quarter of 2010. Accordingly, the
accompanying consolidated statements of income (loss) and
accompanying notes to the consolidated financial statements have
been updated to retroactively reclassify the operating results
of these assets as discontinued operations for all periods
presented. See Note 21 — Discontinued Operations
for additional discussion in Part II,
Item 8. — Financial Statements and Supplementary
Data.
Environmental
Compliance
Nabors does not currently anticipate that compliance with
currently applicable environmental regulations and controls will
significantly change its competitive position, capital spending
or earnings during 2011. Nabors believes it is in material
compliance with applicable environmental rules and regulations,
and the cost of such compliance is not material to the business
or financial condition of Nabors. For a more detailed
description of the environmental laws and regulations applicable
to Nabors’ operations, see Part I,
Item 1A. — Risk Factors —
Changes to
or noncompliance with governmental regulation or exposure to
environmental liabilities could adversely affect Nabors’
results of operations.
| ITEM 1A. | RISK FACTORS |
In addition to the other information set forth elsewhere in this
report, the following factors should be carefully considered
when evaluating Nabors. The risks described below are not the
only ones facing Nabors. Additional risks not presently known to
us or that we currently deem immaterial may also impair our
business operations.
Our business, financial condition or results of operations could
be materially adversely affected by any of these risks.
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We
have a substantial amount of debt outstanding
As of December 31, 2010, we had long-term debt outstanding
of approximately $4.4 billion, including $1.4 billion
in current maturities, and cash and cash equivalents and
investments of $841.5 million, including $40.3 million
of long-term investments and other receivables. Long-term
investments and other receivables include $32.9 million in
oil and gas financing receivables. Our ability to service our
debt obligations depends in large part upon the level of cash
flows generated by our subsidiaries’ operations, possible
dispositions of non-core assets, availability under our
unsecured revolving credit facility and our ability to access
the capital markets. At December 31, 2010, we had
$700 million available under a senior unsecured revolving
credit facility; in January 2011, we added another lender to the
facility raising the amount available to $750 million. On
February 11, 2011, one of our subsidiaries established a
credit facility, which we unconditionally guarantee, for
approximately US$50 million. If our 0.94% senior
exchangeable notes were exchanged before their maturity in May
2011, the required cash payment could have a significant impact
on our level of cash and cash equivalents and investments
available to meet our other cash obligations. We calculate our
leverage in relation to capital (i.e., shareholders’
equity) utilizing two commonly used ratios:
| • | Gross funded debt to capital, which is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portions of long-term debt and (3) long-term debt; and | |
| • | Net funded debt to capital, which is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. |
At December 31, 2010, our gross funded debt to capital
ratio was 0.42:1 and our net funded debt to capital ratio was
0.37:1.
Fluctuations
in oil and natural gas prices could adversely affect drilling
activity and our revenues, cash flows and
profitability
Our operations depend on the level of spending by oil and gas
companies for exploration, development and production
activities. Both short-term and long-term trends in oil and
natural gas prices affect these levels. Oil and natural gas
prices, as well as the level of drilling, exploration and
production activity, can be highly volatile. Worldwide military,
political and economic events, including initiatives by the
Organization of Petroleum Exporting Countries, affect both the
demand for, and the supply of, oil and natural gas. Weather
conditions, governmental regulation (both in the United States
and elsewhere), levels of consumer demand, the availability of
pipeline capacity, and other factors beyond our control may also
affect the supply of and demand for oil and natural gas. Recent
volatility and the effects of recent declines in oil and natural
gas prices are likely to continue in the near future, especially
given the general contraction in the world’s economy that
began during 2008. We believe that any prolonged suppression of
oil and natural gas prices could continue to depress the level
of exploration and production activity. Lower oil and natural
gas prices have also caused some of our customers to seek to
terminate, renegotiate or fail to honor our drilling contracts
and affected the fair market value of our rig fleet, which in
turn has resulted in impairments of our assets. A prolonged
period of lower oil and natural gas prices could affect our
ability to retain skilled rig personnel and affect our ability
to access capital to finance and grow our business. There can be
no assurances as to the future level of demand for our services
or future conditions in the oil and natural gas and oilfield
services industries.
Uncertain
or negative global economic conditions could continue to
adversely affect our results of operations
The recent and substantial volatility and extended declines in
oil and natural gas prices in response to a weakened global
economic environment has adversely affected our results of
operations. In addition, economic conditions have resulted in
substantial uncertainty in the capital markets and both access
to and terms of available financing. During 2009, many of our
customers curtailed their drilling programs, which, in many
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cases, has resulted in a decrease in demand for drilling rigs
and a reduction in dayrates and utilization. Additionally, some
customers have terminated drilling contracts prior to the
expiration of their terms. A prolonged period of lower oil and
natural gas prices could continue to impact our industry and our
business, including our future operating results and the ability
to recover our assets, including goodwill, at their stated
values. In addition, some of our customers could experience an
inability to pay suppliers, including us, in the event they are
unable to access the capital markets to fund their business
operations. Likewise, our suppliers may be unable to sustain
their current level of operations, fulfill their commitments
and/or
fund
future operations and obligations. Each of these could adversely
affect our operations.
As a
holding company, we depend on our subsidiaries to meet our
financial obligations
We are a holding company with no significant assets other than
the stock of our subsidiaries. In order to meet our financial
needs, we rely exclusively on repayments of interest and
principal on intercompany loans that we have made to our
operating subsidiaries and income from dividends and other cash
flow from our subsidiaries. There can be no assurance that our
operating subsidiaries will generate sufficient net income to
pay us dividends or sufficient cash flow to make payments of
interest and principal to us. In addition, from time to time,
our operating subsidiaries may enter into financing arrangements
that contractually restrict or prohibit these types of upstream
payments. There can also be adverse tax consequences associated
with paying dividends.
Our
access to borrowing capacity could be affected by the recent
instability in the global financial markets
Our ability to access capital markets or to otherwise obtain
sufficient financing is enhanced by our senior unsecured debt
ratings as provided by Fitch Ratings, Moody’s Investor
Service and Standard & Poor’s and our historical
ability to access those markets as needed. A credit downgrade
may impact our future ability to access credit markets, which is
important for purposes of both meeting our financial obligations
and funding capital requirements to finance and grow our
businesses.
We
operate in a highly competitive industry with excess drilling
capacity, which may adversely affect our results of
operations
The oilfield services industry is very competitive. Contract
drilling companies compete primarily on a regional basis, and
competition may vary significantly from region to region at any
particular time. Many drilling, workover and well-servicing rigs
can be moved from one region to another in response to changes
in levels of activity and market conditions, which may result in
an oversupply of rigs in an area. In many markets where we
operate, the number of rigs available for use exceeds the demand
for rigs, resulting in price competition. Most drilling and
workover contracts are awarded on the basis of competitive bids,
which also results in price competition. The land drilling
market generally is more competitive than the offshore drilling
market because there are larger numbers of rigs and competitors.
The
nature of our operations presents inherent risks of loss that
could adversely affect our results of operations
Our operations are subject to many hazards inherent in the
drilling, workover and well-servicing and pressure pumping
industries, including blowouts, cratering, explosions, fires,
loss of well control, loss of or damage to the wellbore or
underground reservoir, damaged or lost drilling equipment and
damage or loss from inclement weather or natural disasters. Any
of these hazards could result in personal injury or death,
damage to or destruction of equipment and facilities, suspension
of operations, environmental and natural resources damage and
damage to the property of others. Our offshore operations are
also subject to the hazards of marine operations including
capsizing, grounding, collision, damage from hurricanes and
heavy weather or sea conditions and unsound ocean bottom
conditions. Our operations are also subject to risks of war,
civil disturbances or other political events.
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Accidents may occur, we may be unable to obtain desired
contractual indemnities, and our insurance may prove inadequate
in certain cases. The occurrence of an event not fully insured
or indemnified against, or the failure or inability of a
customer or insurer to meet its indemnification or insurance
obligations, could result in substantial losses. In addition,
insurance may not be available to cover any or all of these
risks. Even if available, insurance may be inadequate or
insurance premiums or other costs may rise significantly in the
future making insurance prohibitively expensive. We expect to
continue to face upward pressure in our insurance renewals; our
premiums and deductibles may be higher, and some insurance
coverage may either be unavailable or more expensive than it has
been in the past. Moreover, our insurance coverage generally
provides that we assume a portion of the risk in the form of a
deductible or self-insured retention. We may choose to increase
the levels of deductibles (and thus assume a greater degree of
risk) from time to time in order to minimize our overall costs.
Future
price declines may result in a writedown of our oil and gas
asset carrying values
We follow the successful-efforts method of accounting for our
consolidated subsidiaries’ oil and gas activities. Under
the successful-efforts method, lease acquisition costs and all
development costs are capitalized. Our provision for depletion
is based on these capitalized costs and is determined on a
property-by-property
basis using the
units-of-production
method. Proved property acquisition costs are amortized over
total proved reserves. Costs of wells and related equipment and
facilities are amortized over the life of proved developed
reserves. Proved oil and gas properties are reviewed when
circumstances suggest the need for such a review and are written
down to their estimated fair value, if required. Unproved
properties are reviewed periodically to determine if there has
been impairment of the carrying value; any impairment is
expensed in that period. The estimated fair value of our proved
reserves generally declines when there is a significant and
sustained decline in oil and natural gas prices. During 2010,
2009 and 2008, our impairment tests on the wholly owned oil and
gas-related assets in our Oil and Gas operating segment resulted
in impairment charges of $137.8 million, $48.6 million
and $21.5 million, respectively. Any sustained further
decline in oil and natural gas prices or reserve quantities
could require further writedown of the value of our proved oil
and gas properties if the estimated fair value of these
properties falls below their net book value.
Our unconsolidated oil and gas joint ventures, which we account
for under the equity method of accounting, utilize the full-cost
method of accounting for costs related to oil and natural gas
properties. Under this method, all of these costs (for both
productive and nonproductive properties) are capitalized and
amortized on an aggregate basis over the estimated lives of the
properties using the
units-of-production
method. However, these capitalized costs are subject to a
ceiling test which limits the costs to the aggregate of
(i) the present value of future net revenues attributable
to proved oil and natural gas reserves, discounted at 10%, plus
(ii) the lower of cost or market value of unproved
properties. The full-cost ceiling was evaluated at
December 31, 2010 and 2009 using the
12-month
average price, whereas during 2008, the full-cost ceiling was
evaluated using year-end prices. During 2010, our unconsolidated
oil and gas joint ventures did not record full-cost ceiling test
writedowns. During 2009 and 2008, the ventures recorded
full-cost ceiling test writedowns of which $237.1 million
and $228.3 million, respectively, represented our
proportionate share. Any sustained further decline in oil and
natural gas prices, or other factors, without other mitigating
circumstances, could cause other future writedowns of
capitalized costs and asset impairments that could adversely
affect our results of operations.
Our
acquisition of Superior may not be as financially or
operationally successful as contemplated
In evaluating the acquisition of Superior, we made certain
business assumptions and determinations based on our due
diligence. However, these assumptions and determinations involve
risks and uncertainties that may cause them to be inaccurate. As
a result, we may not realize the full benefits that we expect
from the acquisition. For example, our assumptions as to future
revenue with respect to expanding internationally and achieving
synergies in North America by integrating Superior’s
pumping services with our drilling and workover offerings may
prove to be incorrect. If they are, the financial success of the
acquisition may be materially adversely affected.
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The
profitability of our operations could be adversely affected by
war, civil disturbance, or political or economic turmoil,
fluctuation in currency exchange rates and local import and
export controls
We derive a significant portion of our business from global
markets, including major operations in Canada, South America,
Mexico, the Caribbean, the Middle East, the Far East, Russia and
Africa. These operations are subject to various risks, including
the risk of war, civil disturbances and governmental activities
that may limit or disrupt markets, restrict the movement of
funds or result in the deprivation of contract rights or the
taking of property without fair compensation. In some countries,
our operations may be subject to the additional risk of
fluctuating currency values and exchange controls, such as last
year’s currency devaluation in Venezuela. We are subject to
various laws and regulations that govern the operation and
taxation of our business and the import and export of our
equipment from country to country, the imposition, application
and interpretation of which can prove to be uncertain.
The
loss of key executives could reduce our competitiveness and
prospects for future success
The successful execution of our strategies central to our future
success will depend, in part, on a few of our key executive
officers. We have entered into employment agreements with our
Chairman and Chief Executive Officer, Eugene M. Isenberg and our
Deputy Chairman, President and Chief Operating Officer, Anthony
G. Petrello, with terms through March 30, 2013. If
Mr. Isenberg’s employment is terminated in the event
of death or disability, or without cause or in the event of a
change in control, a cash payment of $100 million will be
made by the Company. If Mr. Petrello’s employment is
terminated in the event of death or disability, the Company will
make a cash payment of $50 million; or in the event of
termination without cause or in the event of a change in
control, the Company will make a cash payment based on a formula
of three times the average of his base salary and annual bonus
paid during the three fiscal years preceding the termination. We
do not carry significant amounts of key man insurance. The loss
of Mr. Isenberg or Mr. Petrello could have an adverse
effect on our financial condition or results of operations.
Changes
to or noncompliance with governmental regulation or exposure to
environmental liabilities could adversely affect our results of
operations
The drilling of oil and gas wells is subject to various federal,
state and local laws, rules and regulations. Our cost of
compliance with these laws, rules and regulations may be
substantial. For example, federal law imposes on
“responsible parties” a variety of regulations related
to the prevention of oil spills, and liability for removal costs
and natural resource, real or personal property and certain
economic damages arising from such spills. Some of these laws
may impose strict liability for these costs and damages without
regard to the conduct of the parties. As an owner and operator
of onshore and offshore rigs and transportation equipment, we
may be deemed to be a responsible party under federal law. In
addition, our well-servicing, workover and production services
operations routinely involve the handling of significant amounts
of materials, some of which are classified as solid or hazardous
wastes or hazardous substances. Various state and federal laws
govern the containment and disposal of hazardous substances,
oilfield waste and other waste materials, the use of underground
storage tanks and the use of underground injection wells. We
employ personnel responsible for monitoring environmental
compliance and arranging for remedial actions that may be
required from time to time and also use consultants to advise on
and assist with our environmental compliance efforts.
Liabilities are recorded when the need for environmental
assessments
and/or
remedial efforts become known or probable and the cost can be
reasonably estimated.
The scope of laws protecting the environment has expanded,
particularly outside the United States, and this trend is
expected to continue. The violation of environmental laws and
regulations can lead to the imposition of administrative, civil
or criminal penalties, remedial obligations, and in some cases
injunctive relief. Violations may also result in liabilities for
personal injuries, property and natural resource damage and
other costs and claims. We are not always successful in
allocating all risks of these environmental liabilities to
customers, and it is possible that customers who assume the
risks will be financially unable to bear any resulting costs.
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Under the Comprehensive Environmental Response, Compensation and
Liability Act, as amended, also known as CERCLA or Superfund,
and similar state laws and regulations, liability for release of
a hazardous substance into the environment can be imposed
jointly on the entire group of responsible parties or separately
on any one of the responsible parties, without regard to fault
or the legality of the original conduct of any party that
contributed to the release. Liability under CERCLA may include
costs of cleaning up the hazardous substances that have been
released into the environment and damages to natural resources.
Changes in environmental laws and regulations may also
negatively impact the operations of oil and natural gas
exploration and production companies, which in turn could have
an adverse effect on us. For example, legislation has been
proposed from time to time in the U.S. Congress that would
reclassify some oil and natural gas production wastes as
hazardous wastes under the Resources Conservation and Recovery
Act, which would make the reclassified wastes subject to more
stringent handling, disposal and
clean-up
requirements. Legislators and regulators in the United States
and other jurisdictions where we operate also focus increasingly
on restricting the emission of carbon dioxide, methane and other
greenhouse gases that may contribute to warming of the
Earth’s atmosphere, and other climatic changes. The
U.S. Congress has considered legislation designed to reduce
emission of greenhouse gases, and some states in which we
operate have passed legislation or adopted initiatives, such as
the Regional Greenhouse Gas Initiative in the northeastern
United States and the Western Regional Climate Action
Initiative, which establish greenhouse gas inventories
and/or
cap-and-trade
programs. Some international initiatives have also been adopted,
such as the United Nations Framework Convention on Climate
Change’s “Kyoto Protocol”, to which the United
States is not a party. In addition, the U.S. Environmental
Protection Agency (“EPA”) has published findings that
emissions of greenhouses gases present an endangerment to public
health and the environment, paving the way for regulations that
would restrict emissions of greenhouse gases under existing
provisions of the Clean Air Act.
In October 2009, the EPA enacted rules requiring the reporting
of greenhouse gas emissions from large sources and suppliers in
the United States. Although we do not believe these rules
currently apply to us, the EPA has proposed expanding the rules
to include onshore oil and natural gas production, processing,
transmission, storage, and distribution facilities beginning in
2012 for emissions occurring in 2011. The enactment of such
hazardous waste legislation or future or more stringent
regulation of greenhouse gases could dramatically increase
operating costs for oil and natural gas companies and could
reduce the market for our services by making many wells
and/or
oilfields uneconomical to operate.
The U.S. Oil Pollution Act of 1990, as amended, imposes
strict liability on responsible parties for removal costs and
damages resulting from discharges of oil into U.S. waters.
In addition, the Outer Continental Shelf Lands Act provides the
federal government with broad discretion in regulating the
leasing of offshore oil and gas production sites.
Increased
regulation of hydraulic fracturing could result in reductions or
delays in drilling and completing new oil and natural gas wells,
which could adversely impact the demand for fracturing and other
services
Superior performs hydraulic fracturing, a process sometimes used
in the completion of oil and gas wells whereby water, sand and
chemicals are injected under pressure into subsurface formations
to stimulate gas and, to a lesser extent, oil production. In
March 2010, the EPA announced that it would study the potential
adverse impact that fracturing may have on water quality and
public health. Legislation has also been introduced in the
U.S. Congress and some states that would require the
disclosure of chemicals used in the fracturing process. If
enacted, the legislation could require fracturing activities to
meet permitting and financial assurance requirements, adhere to
certain construction specifications, fulfill monitoring,
reporting and recordkeeping requirements and meet plugging and
abandonment requirements. Any new laws regulating fracturing
activities could cause operational delays or increased costs in
exploration and production, which could adversely affect the
demand for fracturing services.
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Because
our option, warrant and convertible securities holders have a
considerable number of common shares available for issuance and
resale, significant issuances or resales in the future could
adversely affect the market price of our common
shares
As of February 24, 2011, we had 800,000,000 authorized
common shares, of which 315,558,810 shares were
outstanding. In addition, 46,780,820 common shares were reserved
for issuance pursuant to option and employee benefit plans, and
39,814,194 shares were reserved for issuance upon
conversion or repurchase of outstanding senior exchangeable
notes. The sale, or availability for sale, of substantial
amounts of our common shares in the public market, whether
directly by us or resulting from the exercise of warrants or
options (and, where applicable, sales pursuant to Rule 144
under the Securities Act) or the conversion into common shares,
or repurchase of debentures and notes using common shares, would
be dilutive to existing security holders, could adversely affect
the prevailing market price of our common shares and could
impair our ability to raise additional capital through the sale
of equity securities.
Provisions
in our organizational documents and executive contracts may
deter a change of control transaction and decrease the
likelihood of a shareholder receiving a change of control
premium
Our Board of Directors is divided into three classes, with each
class serving a staggered three-year term. In addition, the
Board of Directors has the authority to issue a significant
number of common shares and up to 25,000,000 preferred shares,
as well as to determine the price, rights (including voting
rights), conversion ratios, preferences and privileges of the
preferred shares, in each case without any vote or action by the
holders of our common shares. Although we have no current plans
to issue preferred shares, our classified Board, as well as its
ability to issue preferred shares, may discourage, delay or
prevent changes in control of Nabors that are not supported by
the Board, thereby preventing some of our shareholders from
realizing a premium on their shares. In addition, the
requirement in the indenture for our 0.94% senior
exchangeable notes due 2011 to pay a make-whole premium in the
form of an increase in the exchange rate in certain
circumstances could have the effect of making a change in
control of Nabors more expensive.
We have employment agreements with our Chairman and Chief
Executive Officer, Eugene M. Isenberg, and our Deputy Chairman,
President and Chief Operating Officer, Anthony G. Petrello.
These agreements have
change-in-control
provisions that could result in significant cash payments to
Messrs. Isenberg and Petrello.
We may
have additional tax liabilities
We are subject to income taxes in the United States and numerous
other jurisdictions. Significant judgment is required in
determining our worldwide provision for income taxes. In the
ordinary course of our business, there are many transactions and
calculations where the ultimate tax determination is uncertain.
We are regularly audited by tax authorities. Although we believe
our tax estimates are reasonable, the final determination of tax
audits and any related litigation could be materially different
than what is reflected in income tax provisions and accruals. An
audit or litigation could materially affect our financial
position, income tax provision, net income, or cash flows in the
period or periods challenged. It is also possible that future
changes to tax laws (including tax treaties) could impact our
ability to realize the tax savings recorded to date.
On September 14, 2006, Nabors Drilling International
Limited, one of our wholly owned Bermuda subsidiaries
(“NDIL”), received a Notice of Assessment (the
“Notice”) from Mexico’s federal tax authorities
in connection with the audit of NDIL’s Mexico branch for
2003. The Notice proposes to deny depreciation expense
deductions relating to drilling rigs operating in Mexico in
2003. The Notice also proposes to deny a deduction for payments
made to an affiliated company for the procurement of labor
services in Mexico. The amount assessed was approximately
$19.8 million (including interest and penalties). Nabors
and its tax advisors previously concluded that the deductions
were appropriate and more recently that the government’s
position lacks merit. NDIL’s Mexico branch took similar
deductions for depreciation and labor expenses from 2004 to
2008. On June 30, 2009, the government proposed similar
assessments against the Mexico branch of another wholly owned
Bermuda subsidiary, Nabors Drilling International II Ltd.
(“NDIL II”) for 2006. We anticipate that a similar
assessment will eventually be proposed against NDIL for 2004
through 2008 and against NDIL II for 2007 to 2010. We believe
that the potential assessments will range from $6 million
to
17
Table of Contents
$26 million per year for the period from 2004 to 2009, and
in the aggregate, would be approximately $90 million to
$95 million. Although we believe that any assessments
related to the 2004 to 2010 years lack merit, a reserve has
been recorded in accordance with accounting principles generally
accepted in the United States of America (“GAAP”). The
statute of limitations for NDIL’s 2004 tax year recently
expired. Accordingly, during the fourth quarter of 2010, we
released $7.4 million from our tax reserves, which
represented the reserve recorded for that tax year. If these
additional assessments were to be made and we ultimately did not
prevail, we would be required to recognize additional tax for
the amount in excess of the current reserve.
Proposed
tax legislation could mitigate or eliminate the benefits of our
2002 reorganization as a Bermuda company
Various bills have been introduced in the U.S. Congress
that could reduce or eliminate the tax benefits associated with
our reorganization as a Bermuda company. Legislation enacted by
the U.S. Congress in 2004 provides that a corporation that
reorganized in a foreign jurisdiction on or after March 4,
2003 be treated as a domestic corporation for U.S. federal
income tax purposes. Nabors’ reorganization was completed
on June 24, 2002. There have been and we expect that there
may continue to be legislation proposed by the
U.S. Congress from time to time which, if enacted, could
limit or eliminate the tax benefits associated with our
reorganization.
Because we cannot predict whether legislation will ultimately be
adopted, no assurance can be given that the tax benefits
associated with our reorganization will ultimately accrue to the
benefit of the Company and its shareholders. It is possible that
future changes to the tax laws (including tax treaties) could
impact our ability to realize the tax savings recorded to date,
as well as future tax savings, resulting from our reorganization.
Legal
proceedings could affect our financial condition and results of
operations
We are subject to legal proceedings and governmental
investigations from time to time that include employment, tort,
intellectual property and other claims, and purported class
action and shareholder derivative actions. We are also subject
to complaints and allegations from former, current or
prospective employees from time to time, alleging violations of
employment-related laws. Lawsuits or claims could result in
decisions against us that could have an adverse effect on our
financial condition or results of operations.
Our
financial results could be affected by changes in the value of
our investment portfolio
We invest our excess cash in a variety of investment vehicles,
some of which are subject to market fluctuations resulting from
a variety of economic factors or factors associated with a
particular investment, including without limitation, overall
declines in the equity markets, currency and interest rate
fluctuations, volatility in the credit markets, exposures
related to concentrations of investments in a particular fund or
investment, exposures related to hedges of financial positions,
and the performance of a particular fund or investment managers.
As a result, events or developments that negatively affect the
value of our investments could have an adverse effect on our
results of operations.
We do
not currently intend to pay dividends on our common
shares
We have not paid any cash dividends on our common shares since
1982 and have no current intention to do so. However, we can
give no assurance that we will not reevaluate our position on
dividends in the future.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
Not applicable.
18
Table of Contents
| ITEM 2. | PROPERTIES |
Nabors’ principal executive offices are located in
Hamilton, Bermuda. We own or lease executive and administrative
office space in Houston, Texas and other areas across the world.
Many of the international drilling rigs and some of the Alaska
rigs in our fleet are supported by mobile camps which house the
drilling crews and a significant inventory of spare parts and
supplies. In addition, we own various trucks, forklifts, cranes,
earth-moving and other construction and transportation
equipment, including various helicopters, fixed-wing aircraft
and heliportable well-service equipment, which are used to
support drilling and logistics operations. We also own or lease
a number of facilities and storage yards used in support of
operations in each of our geographic markets.
Nabors and its subsidiaries own certain mineral interests in
connection with their investing and operating activities. The
operations of our Oil and Gas operating segment focus on the
exploration for and the acquisition, development and production
of natural gas, oil and natural gas liquids in the United
States, the Canada provinces of Alberta and British Columbia,
and Colombia.
Our Oil and Gas operating segment includes our wholly owned oil
and gas assets and our unconsolidated oil and gas joint
ventures. In December 2008, the SEC revised oil and gas
reporting disclosures, which clarified that we should consider
our equity-method investments when determining whether we have
significant oil and gas activities beginning in 2009. A one-year
deferral of the disclosure requirements was allowed if an entity
became subject to the requirements because of the change to the
definition of significant oil and gas activities. When operating
results from our wholly owned oil and gas activities were
considered with operating results from our unconsolidated oil
and gas joint ventures, which we account for under the equity
method of accounting, we determined that we had significant oil
and gas activities under the new definition. Accordingly, we are
presenting the information with regard to our oil and gas
producing activities as of and for the year ended
December 31, 2010.
The estimates of net proved oil and gas reserves are based on
reserve reports as of December 31, 2010, which were
prepared by independent petroleum engineers. AJM Petroleum
Consultants prepared reports of estimated proved oil and gas
reserves for our wholly owned assets in Canada. Miller and
Lents, Ltd. prepared reports of estimated proved oil and gas
reserves for both our wholly owned assets and our U.S. joint
venture’s interests in natural gas and oil properties
located in the United States. Netherland, Sewell &
Associates, Inc. prepared reports of estimated proved oil
reserves for certain oil properties located in Cat Canyon and
West Cat Canyon Fields, Santa Barbara County, California.
Lonquist & Co., LLC prepared reports of estimated
proved oil and gas reserves for our wholly owned assets in
Colombia.
Summary
of Oil and Gas Reserves
The table below summarizes the proved reserves in each
geographic area and by product type for our wholly owned
subsidiaries and our proportionate interests in our equity
companies. We report proved reserves on the basis of the average
of the
first-day-of-the-month
price for each month during the last
12-month
period. Estimates of volumes of proved reserves of natural gas
at year end are expressed in billions of cubic feet
(“Bcf”) at a pressure base of 14.73 pounds per square
inch for natural gas and in millions of barrels
(“MMBbls”) for oil and natural gas liquids.
For our wholly owned properties in the United States, the prices
used in our reserve reports were $3.72 per mcf for the
12-month
average of natural gas, $36.43 per barrel for natural gas
liquids and $61.12 per barrel for oil at December 31, 2010.
The prices used in the reserve reports by our unconsolidated
U.S. joint venture were $4.53 per mcf for the
12-month
average of natural gas, $39.04 per barrel for natural gas
liquids and $70.60 per barrel for oil at December 31, 2010.
For our wholly owned properties in Canada, the price used in our
reserve reports was $2.81 per mcf for the
12-month
average of natural gas at December 31, 2010. The
12-month
average price for natural gas used in the reserve report by our
unconsolidated Canada joint venture was $2.78 per mcf at
December 31, 2010. For our wholly owned properties in
Colombia, the price used in our reserve reports was $78.21 per
barrel for oil at December 31, 2010. The oil price used in
the reserve report by our unconsolidated Colombia joint venture
was $76.00 per barrel at December 31, 2010.
19
Table of Contents
No major discovery or other favorable or adverse event has
occurred since December 31, 2010, that would cause a
significant change in the estimated proved reserves as of that
date.
| Reserves | ||||||||
|
Liquids
|
Natural Gas
|
|||||||
| Reserve Category | (MMBbls) | (Bcf) | ||||||
|
Proved
|
||||||||
|
Developed
|
||||||||
|
Consolidated Subsidiaries
|
||||||||
|
United States
|
2.7 | (2) | 17.1 | |||||
|
Canada
|
— | 5.6 | ||||||
|
Colombia
|
1.6 | — | ||||||
|
Total Consolidated
|
4.3 | 22.7 | ||||||
|
Equity Companies
(1)
|
||||||||
|
United States
|
3.0 | 147.1 | ||||||
|
Canada
|
— | 5.1 | ||||||
|
Colombia
|
0.5 | — | ||||||
|
Total Equity Companies
|
3.5 | 152.2 | ||||||
|
Total Developed
|
7.8 | 174.9 | ||||||
|
Undeveloped
|
||||||||
|
Consolidated Subsidiaries
|
||||||||
|
United States
|
18.5 | 2.7 | ||||||
|
Canada
|
— | — | ||||||
|
Colombia
|
.4 | — | ||||||
|
Total Consolidated
|
18.9 | 2.7 | ||||||
|
Equity Companies
(1)
|
||||||||
|
United States
|
4.9 | 405.7 | ||||||
|
Canada
|
— | — | ||||||
|
Colombia
|
1.3 | — | ||||||
|
Total Equity Companies
|
6.2 | 405.7 | ||||||
|
Total Proved
|
25.1 | 408.4 | ||||||
| (1) | Represents our proportionate interests in our equity companies. | |
| (2) | During 2010, we purchased a 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County California for $25 million. At December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls. Workovers on approximately 273 productive wells began in late 2010, and 22 wells were producing as of December 31, 2010. The price used in our reserve report was $65.641 per barrel for oil at December 31, 2010. |
In the preceding reserve information, consolidated subsidiary
and our proportionate interests in our equity company reserves
are reported separately. However, we operate our business with
the same view of equity company reserves as for reserves from
consolidated subsidiaries.
The estimation of proved reserves, which is based on the
requirement of reasonable certainty, is an ongoing process based
on rigorous technical evaluations, commercial and market
assessments and detailed analysis of well information such as
flow rates and reservoir pressure declines. Furthermore, we
record proved reserves only for projects that have received
significant funding commitments by management made toward the
development of the reserves. Although we are reasonably certain
that proved reserves will be produced, the timing and amount
recovered can be affected by a number of factors including
completion of development
20
Table of Contents
projects, reservoir performance, regulatory approvals and
significant changes in projections of long-term oil and natural
gas price levels.
Technologies
Used in Establishing Proved Reserves Additions in
2010
Proved reserves were based on estimates generated through the
integration of available and appropriate data, utilizing well
established technologies that have been demonstrated in the
field to yield repeatable and consistent results.
Data used in these integrated assessments included information
obtained directly from the subsurface via wellbores, such as
well logs, reservoir core samples, fluid samples, static and
dynamic pressure information, production test data, and
surveillance and performance information. The data utilized also
included subsurface information obtained through indirect
measurements including high-quality
2-D
and
3-D
seismic
data, calibrated with available well control. Where applicable,
surface geological information was also utilized. The tools used
to interpret the data included proprietary seismic processing
software, proprietary reservoir modeling and simulation software
and commercially available data analysis packages.
In some circumstances, where appropriate analog reservoirs were
available, reservoir parameters from these analogs were used to
increase the quality of and confidence in the reserves estimates.
Internal
Controls over Proved Reserves
Our Oil and Gas operating segment is managed by and staffed with
individuals who have an average of more than 20 years of
technical experience in the petroleum industry. We maintain
computerized records of our reserve estimates and production
data. Appropriate controls, including limitations on access and
updating capabilities, are in place to ensure data integrity. We
engage qualified third-party reservoir engineers and perform
reviews to ensure reserve estimations include all properties
owned and are based on correct working and net revenue
interests. Key components of the reserve estimation process
include technical evaluations and analysis of well and field
performance and a rigorous peer review. No changes may be made
to reserve estimates unless these changes have been thoroughly
reviewed and evaluated by authorized personnel at Nabors. After
all changes are made, senior management reviews the estimates
for final endorsement.
Proved
Undeveloped Reserves
At December 31, 2010, approximately 559 billion cubic feet
equivalent (“Bcfe”) of our proved reserves were
classified as proved undeveloped, which represented 71.6% of the
780.7 Bcfe reported in proved reserves. This amount is inclusive
of both consolidated subsidiaries and equity company reserves.
Progress was made in converting proved undeveloped reserves into
proved developed reserves in 2010. During 2010, we completed
development work in over 12 fields and participated in numerous
major project
start-ups
that resulted in the transfer of approximately 62 Bcfe from
proved undeveloped to proved developed reserves. We estimate
that 35% of our current proved undeveloped reserves will be
developed by year 2012 and all of our current proved undeveloped
reserves will be developed by year 2016.
21
Table of Contents
Oil and
Gas Production, Production Prices and Production Costs
Oil
and Gas Production
The table below summarizes production by final product sold,
average production sales price and average production cost, each
by geographic area for the year ended December 31, 2010.
Production costs are costs to operate and maintain our wells and
related equipment and include the cost of labor, well-service
and repair, location maintenance, power and fuel,
transportation, cost of product, property taxes and
production-related general and administrative costs.
| United States | Canada | Colombia | Total | |||||||||||||||||||||||||||||
|
Liquids
|
Natural Gas
|
Liquids
|
Natural Gas
|
Liquids
|
Natural Gas
|
Liquids
|
Natural Gas
|
|||||||||||||||||||||||||
| (MMBbls) | (Bcf) | (MMBbls) | (Bcf) | (MMBbls) | (Bcf) | (MMBbls) | (Bcf) | |||||||||||||||||||||||||
|
Oil and natural gas liquids production
|
||||||||||||||||||||||||||||||||
|
Consolidated Subsidiaries
|
.073 | 3.533 | — | 3.058 | .230 | — | .303 | 6.591 | ||||||||||||||||||||||||
|
Equity Companies(1)
|
.249 | 12.338 | — | 1.535 | .273 | — | .522 | 13.873 | ||||||||||||||||||||||||
|
Average production sales prices:
|
||||||||||||||||||||||||||||||||
|
Consolidated Subsidiaries
|
$ | 63.77 | $ | 4.19 | $ | — | $ | 3.69 | $ | 72.25 | $ | — | $ | 70.19 | $ | 2.71 | ||||||||||||||||
|
Equity Companies(1)
|
$ | 74.86 | $ | 4.43 | $ | — | $ | 3.93 | $ | 73.90 | $ | — | $ | 58.59 | $ | 4.11 | ||||||||||||||||
|
Average production costs:
|
||||||||||||||||||||||||||||||||
|
Consolidated Subsidiaries
|
$ | 2.14/mcfe | $ | 2.60/mcfe | $ | 34.42/boe | ||||||||||||||||||||||||||
|
Equity Companies(1)
|
$ | 1.33/mcfe | $ | 5.89/mcfe | $ | 33.60/boe | ||||||||||||||||||||||||||
| (1) | Represents our proportionate interests in our equity companies. |
Drilling
and Other Exploratory and Development Activities
During 2010, our drilling program focused on proven and emerging
oil and natural gas basins in the United States. Our drilling
program includes development activities with properties located
in Canada and Colombia that are being actively marketed. The
following tables provide the number of oil and gas wells
completed during 2010.
Number
of Net Productive and Dry Wells Drilled
| For the Year Ended December 31, 2010 | ||||||||
|
Net Productive and
|
Net Dry Exploratory
|
|||||||
| Dry Wells Drilled | Wells Drilled | |||||||
|
Consolidated Subsidiaries
|
||||||||
|
United States
|
1.9 | — | ||||||
|
Canada
|
— | — | ||||||
|
Colombia
|
4.2 | — | ||||||
|
Total Consolidated
|
6.1 | — | ||||||
|
Equity Companies
(1)
|
||||||||
|
United States
|
0.9 | — | ||||||
|
Canada
|
— | — | ||||||
|
Colombia
|
3.3 | 2.1 | ||||||
|
Total Equity Companies
|
4.2 | 2.1 | ||||||
| (1) | Represents our proportionate interests in our equity companies. |
22
Table of Contents
| For the Year Ended December 31, 2010 | ||||||||
|
Net Productive
|
Net Dry
|
|||||||
|
Development Wells
|
Development
|
|||||||
| Drilled | Wells Drilled | |||||||
|
Consolidated Subsidiaries
|
||||||||
|
United States
|
1.2 | 0.1 | ||||||
|
Canada
|
— | — | ||||||
|
Colombia
|
— | — | ||||||
|
Total Consolidated
|
1.2 | 0.1 | ||||||
|
Equity Companies
(1)
|
||||||||
|
United States
|
9.5 | — | ||||||
|
Canada
|
— | — | ||||||
|
Colombia
|
1.6 | — | ||||||
|
Total Equity Companies
|
11.1 | — | ||||||
| (1) | Represents our proportionate interests in our equity companies. |
Present
Activities
The following table provides the number of wells in the process
of drilling as of December 31, 2010.
Wells
Drilling
| United States | Canada | Colombia | Total | |||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
|
Consolidated Subsidiaries
|
17.0 | 0.9 | — | — | — | — | 17.0 | 0.9 | ||||||||||||||||||||||||
|
Equity Companies(1)
|
2.5 | 2.5 | — | — | — | — | 2.5 | 2.5 | ||||||||||||||||||||||||
| (1) | Represents our proportionate interests in our equity companies. |
Oil and
Gas Properties, Wells, Operations and Acreage
Gross
and Net Productive Wells
|
For the Year Ended
|
||||||||
| December 31, 2010 | ||||||||
| Gross | Net | |||||||
|
Consolidated Subsidiaries
|
||||||||
|
United States
|
746.0 | 139.6 | ||||||
|
Canada
|
2.0 | 2.0 | ||||||
|
Colombia
|
7.0 | 4.9 | ||||||
|
Total Consolidated
|
755.0 | 146.5 | ||||||
|
Equity Companies
(1)
|
||||||||
|
United States
|
337.8 | 225.4 | ||||||
|
Canada
|
3.0 | 3.0 | ||||||
|
Colombia
|
7.0 | 3.9 | ||||||
|
Total Equity Companies
|
347.8 | 232.3 | ||||||
| (1) | Represents our proportionate interests in our equity companies. |
23
Table of Contents
Gross
and Net Developed Acreage
| December 31, 2010 | ||||||||||||||||||||||||||||||||
| United States | Canada | Colombia | Total | |||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
|
Consolidated Subsidiaries
|
157,965 | 31,879 | 1,309 | 715 | 883 | 618 | 160,157 | 33,212 | ||||||||||||||||||||||||
|
Equity Companies(1)
|
211,638 | 112,227 | 9,801 | 8,134 | — | — | 221,439 | 120,361 | ||||||||||||||||||||||||
| (1) | Represents our proportionate interests in our equity companies. |
Gross
and Net Undeveloped Acreage
| December 31, 2010 | ||||||||||||||||||||||||||||||||
| United States | Canada | Colombia | Total | |||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
|
Consolidated Subsidiaries
|
347,662 | 128,244 | 46,440 | 34,554 | 546,384 | 247,299 | 940,486 | 410,097 | ||||||||||||||||||||||||
|
Equity Companies(1)
|
574,841 | 218,596 | 83,821 | 53,279 | 739,533 | 448,185 | 1,398,195 | 720,060 | ||||||||||||||||||||||||
| (1) | Represents our proportionate interests in our equity companies. |
Additional information about our properties can be found in
Notes 2 — Summary of Significant Accounting
Policies, 8 — Property, Plant and Equipment (each,
under the caption Property, Plant and Equipment), 16 —
Commitments and Contingencies (under the caption Operating
Leases), and 24 — Supplemental Information on Oil and
Gas Exploration and Production Activities in Part II,
Item 8. — Financial Statements and Supplementary
Data. The revenues and property, plant and equipment by
geographic area for the years ended December 31, 2010, 2009
and 2008, can be found in Note 22 — Segment
Information. A description of our rig fleet is included under
the caption Introduction in Part I,
Item 1. — Business.
Management believes that our existing equipment and facilities
are adequate to support our current level of operations as well
as an expansion of drilling operations in those geographical
areas where we may expand.
| ITEM 3. | LEGAL PROCEEDINGS |
Nabors and its subsidiaries are defendants or otherwise involved
in a number of lawsuits in the ordinary course of business. We
estimate the range of our liability related to pending
litigation when we believe the amount and range of loss can be
estimated. We record our best estimate of a loss when the loss
is considered probable. When a liability is probable and there
is a range of estimated loss with no best estimate in the range,
we record the minimum estimated liability related to the
lawsuits or claims. As additional information becomes available,
we assess the potential liability related to our pending
litigation and claims and revise our estimates. Due to
uncertainties related to the resolution of lawsuits and claims,
the ultimate outcome may differ from our estimates. In the
opinion of management and based on liability accruals provided,
our ultimate exposure with respect to these pending lawsuits and
claims is not expected to have a material adverse effect on our
consolidated financial position or cash flows, although they
could have a material adverse effect on our results of
operations for a particular reporting period.
On July 5, 2007, we received an inquiry from the United
States Department of Justice relating to its investigation of
one of our vendors and compliance with the Foreign Corrupt
Practices Act. The inquiry relates to transactions with and
involving Panalpina, which provided freight forwarding and
customs clearance services to some of our affiliates. To date,
the inquiry has focused on transactions in Kazakhstan, Saudi
Arabia, Algeria and Nigeria. The Audit Committee of our Board of
Directors engaged outside counsel to review some of our
transactions with this vendor, has received periodic updates at
its regularly scheduled meetings, and the Chairman of the Audit
Committee has received updates between meetings as circumstances
warrant. The investigation includes a review of certain amounts
paid to and by Panalpina in connection with obtaining permits
for the temporary importation of equipment and clearance of
goods and materials through customs. Both the SEC and the United
States Department of Justice have been advised of our
investigation.
24
Table of Contents
The ultimate outcome of this investigation or the effect of
implementing any further measures that may be necessary to
ensure full compliance with applicable laws cannot be determined
at this time.
A court in Algeria entered a judgment of approximately
$19.7 million against us related to alleged customs
infractions in 2009. We believe we did not receive proper notice
of the judicial proceedings, and that the amount of the judgment
is excessive. We have asserted the lack of legally required
notice as a basis for challenging the judgment on appeal to the
Algeria Supreme Court. Based upon our understanding of
applicable law and precedent, we believe that this challenge
will be successful. We do not believe that a loss is probable
and have not accrued any amounts related to this matter.
However, the ultimate resolution and the timing thereof are
uncertain. If we are ultimately required to pay a fine or
judgment related to this matter, the amount of the loss could
range from approximately $140,000 to $19.7 million.
In August 2010, Nabors and its wholly owned subsidiary, Diamond
Acquisition Corp. (“Diamond”) were sued in three
putative shareholder class actions. Two of the cases were
dismissed. The remaining case pending,
Jordan Denney,
Individually and on Behalf of All Others Similarly
Situated v. David E. Wallace, et al.,
Civil Action
No. 10-1154,
is pending in the United States District Court for the Western
District of Pennsylvania. The suits were brought against
Superior, the individual members of its board of directors,
certain of Superior’s senior officers, Nabors and Diamond.
The complaints alleged that Superior’s officers and
directors violated various provisions of the Exchange Act and
breached their fiduciary duties in connection with the Superior
Merger, and that Nabors and Diamond aided and abetted these
violations. The complaints sought injunctive relief, including
an injunction against the consummation of the Superior Merger,
monetary damages, and attorney’s fees and costs. The claim
against Superior and its directors is covered by insurance after
a deductible amount. We anticipate settling the claims in the
first or second quarter of 2011, and that any settlement will be
funded by Superior’s insurers to the extent it exceeds our
deductible.
| ITEM 4. | (REMOVED AND RESERVED) |
25
Table of Contents
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
STOCK
PERFORMANCE GRAPH
The following graph illustrates comparisons of five-year
cumulative total returns among Nabors, the S&P 500 Index
and the Dow Jones Oil Equipment and Services Index. Total return
assumes $100 invested on December 31, 2005 in shares of
Nabors, the S&P 500 Index, and the Dow Jones Oil Equipment
and Services Index. It also assumes reinvestment of dividends
and is calculated at the end of each calendar year,
December 31, 2006 — 2010.
| 2006 | 2007 | 2008 | 2009 | 2010 | |||||||||||||||||||||
|
Nabors Industries Ltd.
|
79 | 72 | 32 | 58 | 62 | ||||||||||||||||||||
|
S&P 500 Index
|
116 | 122 | 77 | 97 | 112 | ||||||||||||||||||||
|
Dow Jones Oil Equipment and Services Index
|
113 | 164 | 67 | 111 | 141 | ||||||||||||||||||||
26
Table of Contents
| I. | Market and Share Prices |
Our common shares are traded on the New York Stock Exchange
under the symbol “NBR”. At February 24, 2011,
there were approximately 1,573 shareholders of record. We
have not paid any cash dividends on our common shares since 1982
and currently have no intentions to do so. However, we can give
no assurance that we will not reevaluate our position on
dividends in the future.
The following table sets forth the reported high and low sales
prices of our common shares as reported on the New York Stock
Exchange for the periods indicated.
| Share Price | ||||||||
| Calendar Year | High | Low | ||||||
|
2009
|
||||||||
|
First quarter
|
14.05 | 8.25 | ||||||
|
Second quarter
|
19.79 | 9.38 | ||||||
|
Third quarter
|
21.48 | 13.78 | ||||||
|
Fourth quarter
|
24.07 | 19.18 | ||||||
|
2010
|
||||||||
|
First quarter
|
27.05 | 18.74 | ||||||
|
Second quarter
|
22.82 | 16.90 | ||||||
|
Third quarter
|
19.13 | 15.54 | ||||||
|
Fourth quarter
|
23.93 | 17.36 | ||||||
The following table provides information relating to
Nabors’ repurchase of common shares during the three months
ended December 31, 2010:
|
Approximate Dollar
|
||||||||||||||||
|
Total Number
|
Average
|
Total Number of
|
Value of Shares
|
|||||||||||||
|
of Shares
|
Price Paid
|
Shares Purchased as
|
that May Yet Be
|
|||||||||||||
|
Purchased
|
per
|
Part of Publicly
|
Purchased Under the
|
|||||||||||||
| Period | (1) | Share(1) | Announced Program | Program(2) | ||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||
|
October 1 — October 31
|
— | — | — | $ | 35,458 | |||||||||||
|
November 1 — November 30
|
— | $ | 21.85 | — | $ | 35,458 | ||||||||||
|
December 1 — December 31
|
3,073 | $ | 23.15 | — | $ | 35,458 | ||||||||||
| (1) | Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of stock under our 2003 Employee Stock Plan and option exercises from our 1996 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and our 1998 Employee Stock Plan. The 2003 Employee Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and 1996 Employee Stock Plan provide for the withholding of shares to satisfy tax obligations, but do not specify a maximum number of shares that can be withheld for this purpose. These shares were not purchased as part of a publicly announced program to purchase common shares. | |
| (2) | In July 2006 our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2010, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2010, we had the capacity to repurchase up to an additional $35.5 million of our common shares under the July 2006 share repurchase program. |
See Part III, Item 12. for a description of securities
authorized for issuance under equity compensation plans.
| II. | Dividend Policy |
See Part I, Item 1A. — Risk
Factors —
We do not currently intend to pay
dividends on our common shares
and Part II,
Item 5. — I. Market and Share Prices.
27
Table of Contents
III.
Shareholder Matters
Bermuda has exchange controls which apply to residents in
respect of the Bermuda dollar. As an exempt company, Nabors is
considered to be nonresident for such controls; consequently,
there are no Bermuda governmental restrictions on our ability to
make transfers and carry out transactions in all other
currencies, including currency of the United States.
There is no reciprocal tax treaty between Bermuda and the United
States regarding withholding taxes. Under existing Bermuda law
there is no Bermuda income or withholding tax on dividends paid
by Nabors to its shareholders. Furthermore, no Bermuda tax is
levied on the sale or transfer (including by gift
and/or
on
the death of the shareholder) of Nabors common shares (other
than by shareholders resident in Bermuda).
| ITEM 6. | SELECTED FINANCIAL DATA |
| Year Ended December 31, | ||||||||||||||||||||
| Operating Data(1)(2) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
| (In thousands, except per share amounts and ratio data) | ||||||||||||||||||||
|
Revenues and other income:
|
||||||||||||||||||||
|
Operating revenues
|
$ | 4,174,635 | $ | 3,683,419 | $ | 5,507,542 | $ | 4,938,748 | $ | 4,707,268 | ||||||||||
|
Earnings (losses) from unconsolidated affiliates
|
33,257 | (155,433 | ) | (192,548 | ) | 20,980 | 20,545 | |||||||||||||
|
Investment income (loss)
|
7,648 | 25,599 | 21,412 | (16,290 | ) | 101,907 | ||||||||||||||
|
Total revenues and other income
|
4,215,540 | 3,553,585 | 5,336,406 | 4,943,438 | 4,829,720 | |||||||||||||||
|
Costs and other deductions:
|
||||||||||||||||||||
|
Direct costs
|
2,423,602 | 2,001,404 | 3,100,613 | 2,763,462 | 2,508,611 | |||||||||||||||
|
General and administrative expenses
|
346,661 | 428,161 | 479,194 | 436,274 | 416,582 | |||||||||||||||
|
Depreciation and amortization
|
764,253 | 667,100 | 614,367 | 469,669 | 365,357 | |||||||||||||||
|
Depletion
|
17,943 | 9,417 | 22,308 | 30,904 | 38,580 | |||||||||||||||
|
Interest expense
|
273,044 | 266,039 | 196,718 | 154,919 | 120,507 | |||||||||||||||
|
Losses (gains) on sales and retirements of long-lived assets and
other expense (income), net
|
47,060 | 12,559 | 15,829 | 11,777 | 22,092 | |||||||||||||||
|
Impairments and other charges
|
260,931 | 330,976 | 176,123 | 41,017 | — | |||||||||||||||
|
Total costs and other deductions
|
4,133,494 | 3,715,656 | 4,605,152 | 3,908,022 | 3,471,729 | |||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
82,046 | (162,071 | ) | 731,254 | 1,035,416 | 1,357,991 | ||||||||||||||
|
Income tax expense (benefit)
|
(24,814 | ) | (133,803 | ) | 209,660 | 201,896 | 407,282 | |||||||||||||
|
Subsidiary preferred stock dividend
|
750 | — | — | — | — | |||||||||||||||
|
Income (loss) from continuing operations, net of tax
|
106,110 | (28,268 | ) | 521,594 | 833,520 | 950,709 | ||||||||||||||
|
Income (loss) from discontinued operations, net of tax
|
(11,330 | ) | (57,620 | ) | (41,930 | ) | 31,762 | 24,927 | ||||||||||||
|
Net income (loss)
|
94,780 | (85,888 | ) | 479,664 | 865,282 | 975,636 | ||||||||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
(85 | ) | 342 | (3,927 | ) | 420 | (1,914 | ) | ||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | $ | (85,546 | ) | $ | 475,737 | $ | 865,702 | $ | 973,722 | |||||||||
28
Table of Contents
| Year Ended December 31, | ||||||||||||||||||||
| Operating Data(1)(2) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
| (In thousands, except per share amounts and ratio data) | ||||||||||||||||||||
|
Earnings (losses) per share:
|
||||||||||||||||||||
|
Basic from continuing operations
|
$ | .37 | $ | (.10 | ) | $ | 1.84 | $ | 2.97 | $ | 3.26 | |||||||||
|
Basic from discontinued operations
|
(.04 | ) | (.20 | ) | (.15 | ) | .11 | .09 | ||||||||||||
|
Total Basic
|
$ | .33 | $ | (.30 | ) | $ | 1.69 | $ | 3.08 | $ | 3.35 | |||||||||
|
Diluted from continuing operations
|
$ | .37 | $ | (.10 | ) | $ | 1.80 | $ | 2.89 | $ | 3.16 | |||||||||
|
Diluted from discontinued operations
|
(.04 | ) | (.20 | ) | (.15 | ) | .11 | .08 | ||||||||||||
|
Total Diluted
|
$ | .33 | $ | (.30 | ) | $ | 1.65 | $ | 3.00 | $ | 3.24 | |||||||||
|
Weighted-average number of common shares outstanding:
|
||||||||||||||||||||
|
Basic
|
285,145 | 283,326 | 281,622 | 281,238 | 291,267 | |||||||||||||||
|
Diluted
|
289,996 | 283,326 | 288,236 | 288,226 | 300,677 | |||||||||||||||
|
Capital expenditures and acquisitions of businesses(3)
|
$ | 1,878,063 | $ | 990,287 | $ | 1,578,241 | $ | 1,945,932 | $ | 2,006,286 | ||||||||||
|
Interest coverage ratio(4)
|
7.0:1 | 6.3:1 | 21.0:1 | 32.6:1 | 38.2:1 | |||||||||||||||
| As of December 31, | ||||||||||||||||||||
| Balance Sheet Data(1)(2) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
| (In thousands, except ratio data) | ||||||||||||||||||||
|
Cash, cash equivalents, short-term and long-term investments and
other receivables(5)
|
$ | 841,490 | $ | 1,191,733 | $ | 826,063 | $ | 1,179,639 | $ | 1,653,285 | ||||||||||
|
Working capital
|
458,550 | 1,568,042 | 1,037,734 | 719,674 | 1,650,496 | |||||||||||||||
|
Property, plant and equipment, net
|
7,815,419 | 7,646,050 | 7,331,959 | 6,669,013 | 5,423,729 | |||||||||||||||
|
Total assets
|
11,646,569 | 10,644,690 | 10,517,899 | 10,139,783 | 9,155,931 | |||||||||||||||
|
Long-term debt
|
3,064,126 | 3,940,605 | 3,600,533 | 2,894,659 | 3,457,675 | |||||||||||||||
|
Shareholders’ equity
|
5,328,162 | 5,167,656 | 4,904,106 | 4,801,579 | 3,889,100 | |||||||||||||||
|
Funded debt to capital ratio:
|
||||||||||||||||||||
|
Gross(6)
|
0.42:1 | 0.41:1 | 0.41:1 | 0.39:1 | 0.43:1 | |||||||||||||||
|
Net(7)
|
0.37:1 | 0.33:1 | 0.35:1 | 0.30:1 | 0.28:1 | |||||||||||||||
| (1) | All periods present the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia and the Sea Mar business as discontinued operations. | |
| (2) | Our acquisitions’ results of operations and financial position have been included beginning on the respective dates of acquisition and include Superior (September 2010), Energy Contractors (December 2010), Pragma Drilling Equipment Ltd. assets (May 2006), and 1183011 Alberta Ltd. (January 2006). | |
| (3) | Represents capital expenditures and the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value. | |
| (4) | The interest coverage ratio is a trailing 12-month quotient of the sum of income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, depletion expense, impairments and other charges, income tax expense (benefit) and our proportionate share of full-cost ceiling test writedowns from our unconsolidated oil and gas joint ventures less investment income (loss) divided by cash interest |
29
Table of Contents
| expense plus subsidiary preferred stock dividends. This ratio is a method for calculating the amount of operating cash flows available to cover interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies. | ||
| (5) | The December 31, 2008 and 2007 amounts include $1.9 million and $53.1 million, respectively, in cash proceeds receivable from brokers from the sale of certain long-term investments that are included in other current assets. Additionally, the December 31, 2010, 2009 and 2008 amounts include $32.9 million, $92.5 million and $224.2 million, respectively, in oil and gas financing receivables that are included in long-term investments and other receivables. | |
| (6) | The gross funded debt to capital ratio is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portion of long-term debt and (3) long-term debt. Capital is defined as shareholders’ equity. The gross funded debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies. | |
| (7) | The net funded debt to capital ratio is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. The net funded debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies. |
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Management
Overview
The following Management’s Discussion and Analysis of
Financial Condition and Results of Operations is intended to
help the reader understand the results of our operations and our
financial condition. This information is provided as a
supplement to, and should be read in conjunction with, our
consolidated financial statements and the accompanying notes
thereto.
We have grown from a land drilling business centered in the
U.S. Lower 48 states, Canada and Alaska to an
international business with operations on land and offshore in
many of the major oil and gas markets in the world. Our
worldwide fleet of actively marketed rigs consists of over
550 land drilling rigs, more than 700 rigs for land
well-servicing and workover work in the United States and
Canada, offshore platform rigs,
jack-up
units, barge rigs and a large component of trucks and fluid
hauling vehicles. We invest in oil and gas exploration,
development and production activities in the United States,
Canada and Colombia.
The majority of our business is conducted through our various
Contract Drilling operating segments, which include our
drilling, well-servicing and workover operations and pressure
pumping, on land and offshore. Our oil and gas exploration,
development and production operations are included in our Oil
and Gas operating segment. Our operating segments engaged in
drilling technology and top drive manufacturing, directional
drilling, rig instrumentation and software, and construction and
logistics operations are aggregated in our Other Operating
Segments.
Our businesses depend, to a large degree, on the level of
spending by oil and gas companies for exploration, development
and production activities. Therefore, a sustained increase or
decrease in the price of natural gas or oil, which could have a
material impact on exploration, development and production
activities, could also materially affect our financial position,
results of operations and cash flows.
The magnitude of customer spending on new and existing wells is
the primary driver of our business. The primary determinant of
customer spending is their cash flow and earnings, which (i) in
our U.S. Lower 48 Land Drilling and Canadian Drilling
operations are largely driven by natural gas prices and (ii) in
our Alaskan, International, U.S. Offshore (Gulf of Mexico),
Canadian Well-servicing and U.S. Land Well-servicing
operations by oil prices. Both natural gas and oil prices impact
our customers’ activity levels and spending for our
Pressure Pumping operations. Oil and natural gas liquids prices
are beginning to be more significant
30
Table of Contents
factors in some of the traditionally natural-gas-driven
operating segments. The following table sets forth natural gas
and oil price data per Bloomberg for the last three years:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
|
Commodity prices:
|
||||||||||||||||||||||||||||
|
Average Henry Hub natural gas spot price ($/thousand cubic feet
(mcf))
|
$ | 4.37 | $ | 3.94 | $ | 8.89 | $ | .43 | 11 | % | $ | (4.95 | ) | (56 | )% | |||||||||||||
|
Average West Texas intermediate crude oil spot price ($/barrel)
|
$ | 79.51 | $ | 61.99 | $ | 99.92 | $ | 17.52 | 28 | % | $ | (37.93 | ) | (38 | )% | |||||||||||||
Beginning in the fourth quarter of 2008, there was a significant
reduction in the demand for natural gas and oil that was caused,
at least in part, by the significant deterioration of the global
economic environment including the extreme volatility in the
capital and credit markets. Weaker demand throughout 2009
resulted in sustained lower natural gas and oil prices, which
led to a sharp decline in the demand for drilling and workover
services. During 2010, these commodity prices strengthened in
the latter half of the year and demand for drilling activity
improved. Continued fluctuations in the demand for gas and oil,
among other factors including supply, could contribute to
continued price volatility which may continue to affect demand
for our services and could materially affect our future
financial results.
Operating revenues and Earnings (losses) from unconsolidated
affiliates for the year ended December 31, 2010 totaled
$4.2 billion, representing an increase of
$679.9 million, or 19% as compared to the year ended
December 31, 2009. Adjusted income derived from operating
activities and net income (loss) attributable to Nabors for the
year ended December 31, 2010 totaled $655.4 million
and $94.7 million ($.33 per diluted share), respectively,
representing increases of 55% and 211%, respectively, compared
to the year ended December 31, 2009.
Operating revenues and Earnings (losses) from unconsolidated
affiliates for the year ended December 31, 2009 totaled
$3.5 billion, representing a decrease of $1.8 billion,
or 34% as compared to the year ended December 31, 2008.
Adjusted income derived from operating activities and net income
(loss) attributable to Nabors for the year ended
December 31, 2009 totaled $421.9 million and
$(85.5) million ($(.30) per diluted share), respectively,
representing decreases of 62% and 118%, respectively, compared
to the year ended December 31, 2008.
During 2010, operating results improved as compared to 2009
primarily due to the incremental revenue and positive operating
results from our Pressure Pumping operating segment and
increased drilling activity in 2010 in our U.S. Lower 48
Land Drilling and Canada Well-servicing operations relating to
increased drilling activity in oil and the liquids-oil shale
plays. Our U.S. Well-servicing business also improved with
continuing strong crude oil prices, which have led to increased
activity. However, our operating results and activity levels
continued to be negatively impacted in our U.S. Offshore
operations in response to uncertainty in the regulatory
environment; our Alaskan operations due to key customers’
spending constraints; and elsewhere with less activity in Saudi
Arabia and Mexico, two of our key markets. There was also
improvement in our operating results for 2010 because there were
no full-cost ceiling adjustments recorded by our U.S. oil and
gas joint venture.
Our U.S. Offshore operations were improving during the
first half of 2010 until the Gulf of Mexico explosion and oil
spill occurred mid-year, which resulted in temporary suspension
of offshore drilling and further delays in our customers’
ability to obtain permits, which has limited the use of our
assets. Specifically, operating results have been impacted
because our customers have suspended most of their operations in
the Gulf of Mexico, largely as a result of their inability to
obtain government permits. Although the previously issued
U.S. deepwater drilling moratorium has been lifted, it is
uncertain whether our customers’ ability to obtain
government permits will improve in the near term. Our Alaska
operating segment has been negatively impacted because the
largest operator in the area has curtailed and suspended
drilling operations, creating a surplus of rigs in the market
and causing price competition. We expect that these conditions
will persist and continue to adversely impact our Alaska
operating results through 2011. We expect our International
results to remain flat in 2011 as the increase of land rig
activity is expected to be essentially offset by contract
renewals on our
jack-up
rigs
at significantly lower average dayrates.
31
Table of Contents
During 2010, we recorded impairments and other charges of
$260.9 million. We recognized goodwill and long-lived asset
impairments of approximately $10.7 million and
$27.4 million, respectively, to assets in our
U.S. Offshore operating segment, primarily driven by
current market conditions in the Gulf of Mexico. Additionally,
we recognized long-lived asset impairments of $7.5 million
to our aircraft and some drilling equipment in Canada and
recorded impairments of $23.2 million relating to asset
retirements across our U.S. Lower 48 Land,
U.S. Well-servicing and U.S. Offshore Contract
Drilling segments. Our Oil and Gas operating segment recorded
impairments of $54.3 million relating to an oil and gas
financing receivable and $137.8 million under application
of the successful-efforts method of accounting for our wholly
owned oil and gas-related assets.
During 2009 and 2008, our operating results were negatively
impacted as a result of charges arising from oil and gas
full-cost ceiling test writedowns and other impairments.
Earnings (losses) from unconsolidated affiliates includes
$(189.3) million and $(207.3) million, respectively,
for the years ended December 31, 2009 and 2008,
representing our proportionate share of a full-cost ceiling test
writedown from our unconsolidated U.S. oil and gas joint
venture which utilizes the full-cost method of accounting.
During 2009, our joint venture used a
12-month
average price in the ceiling test calculation as required by the
revised SEC rules whereas during 2008, the ceiling test
calculation used the
single-day,
year-end commodity price that, at December 31, 2008, was
near its low point for that year. The full-cost ceiling test
writedowns are included in our Oil and Gas operating segment
results.
During 2009, impairments and other charges of
$331.0 million included recognition of
other-than-temporary
impairments of $54.3 million relating to our
available-for-sale
securities, and impairments of $64.2 million to long-lived
assets that were retired from our U.S. Offshore, Alaska,
Canada and International contract drilling segments. We also
recognized a goodwill impairment of $14.7 million relating
to Nabors Blue Sky Ltd., one of our Canadian subsidiaries, which
eliminated the remaining goodwill balance relating to remote
aircraft operations in Canada. Additionally, we recorded
impairment charges of $48.6 million to our wholly owned
assets in our Oil and Gas operating segment under application of
the successful-efforts method of accounting for some of our oil
and gas-related assets and $149.1 million relating to an
oil and gas financing receivable during the year ended
December 31, 2009.
During 2008, impairments and other charges of
$176.1 million included goodwill and intangible asset
impairments totaling $154.6 million recorded by our Canada
Well-servicing and Drilling operating segment and Nabors Blue
Sky Ltd. We recognized these goodwill and intangible asset
impairments to reduce the carrying value of these assets to
their estimated fair value. We consider these writedowns
necessary because of the duration of the industry downturn in
Canada and the lack of certainty regarding eventual recovery. We
also recorded impairment charges of $21.5 million to our
wholly owned assets in our Oil and Gas operating segment for
some of our oil and gas-related assets during the year ended
December 31, 2008.
Our operating results for 2011 are still expected to increase
from levels realized during 2010, despite a moderating outlook
of lower commodity prices during 2011 and the related impact on
drilling and well-servicing activity and dayrates. The major
factors that support our expectations of an improved year are:
| • | An expected incremental increase from ancillary well-site services, primarily technical pumping services and down-hole surveying services, resulting from our acquisition in the third quarter of 2010, and | |
| • | The anticipated positive impact on our overall level of drilling and well-servicing activity and margins resulting from our new and upgraded rigs added to our fleet over the past five years, which we expect will enhance our competitive position as market conditions improve. |
32
Table of Contents
The following tables set forth certain information with respect
to our reportable segments and rig activity:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Reportable segments:
|
||||||||||||||||||||||||||||
|
Operating revenues and Earnings (losses) from unconsolidated
affiliates from continuing operations: (1)
|
||||||||||||||||||||||||||||
|
Contract Drilling: (2)
|
||||||||||||||||||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 1,294,853 | $ | 1,082,531 | $ | 1,878,441 | $ | 212,322 | 20 | % | $ | (795,910 | ) | (42 | )% | |||||||||||||
|
U.S. Land Well-servicing
|
444,665 | 412,243 | 758,510 | 32,422 | 8 | % | (346,267 | ) | (46 | )% | ||||||||||||||||||
|
Pressure Pumping(3)
|
321,295 | — | — | 321,295 | 100 | % | — | — | ||||||||||||||||||||
|
U.S. Offshore
|
123,761 | 157,305 | 252,529 | (33,544 | ) | (21 | )% | (95,224 | ) | (38 | )% | |||||||||||||||||
|
Alaska
|
179,218 | 204,407 | 184,243 | (25,189 | ) | (12 | )% | 20,164 | 11 | % | ||||||||||||||||||
|
Canada
|
389,229 | 298,653 | 502,695 | 90,576 | 30 | % | (204,042 | ) | (41 | )% | ||||||||||||||||||
|
International
|
1,093,608 | 1,265,097 | 1,372,168 | (171,489 | ) | (14 | )% | (107,071 | ) | (8 | )% | |||||||||||||||||
|
Subtotal Contract Drilling(4)
|
3,846,629 | 3,420,236 | 4,948,586 | 426,393 | 12 | % | (1,528,350 | ) | (31 | )% | ||||||||||||||||||
|
Oil and Gas (5)(6)
|
40,611 | (158,780 | ) | (118,533 | ) | 199,391 | 126 | % | (40,247 | ) | (34 | )% | ||||||||||||||||
|
Other Operating Segments (7)(8)
|
456,893 | 446,282 | 683,186 | 10,611 | 2 | % | (236,904 | ) | (35 | )% | ||||||||||||||||||
|
Other reconciling items(9)
|
(136,241 | ) | (179,752 | ) | (198,245 | ) | 43,511 | 24 | % | 18,493 | 9 | % | ||||||||||||||||
|
Total
|
$ | 4,207,892 | $ | 3,527,986 | $ | 5,314,994 | $ | 679,906 | 19 | % | $ | (1,787,008 | ) | (34 | )% | |||||||||||||
|
Adjusted income (loss) derived from operating activities from
continuing operations: (1)(10)
|
||||||||||||||||||||||||||||
|
Contract Drilling:
|
||||||||||||||||||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 274,215 | $ | 294,679 | $ | 628,579 | $ | (20,464 | ) | (7 | )% | $ | (333,900 | ) | (53 | )% | ||||||||||||
|
U.S. Land Well-servicing
|
31,597 | 28,950 | 148,626 | 2,647 | 9 | % | (119,676 | ) | (81 | )% | ||||||||||||||||||
|
Pressure Pumping(3)
|
66,651 | — | — | 66,651 | 100 | % | — | — | ||||||||||||||||||||
|
U.S. Offshore
|
9,245 | 30,508 | 59,179 | (21,263 | ) | (70 | )% | (28,671 | ) | (48 | )% | |||||||||||||||||
|
Alaska
|
51,896 | 62,742 | 52,603 | (10,846 | ) | (17 | )% | 10,139 | 19 | % | ||||||||||||||||||
|
Canada
|
22,970 | (7,019 | ) | 61,040 | 29,989 | 427 | % | (68,059 | ) | (111 | )% | |||||||||||||||||
|
International
|
254,744 | 365,566 | 407,675 | (110,822 | ) | (30 | )% | (42,109 | ) | (10 | )% | |||||||||||||||||
|
Subtotal Contract Drilling(4)
|
711,318 | 775,426 | 1,357,702 | (64,108 | ) | (8 | )% | (582,276 | ) | (43 | )% | |||||||||||||||||
|
Oil and Gas(5)(6)
|
6,329 | (190,798 | ) | (159,931 | ) | 197,127 | 103 | % | (30,867 | ) | (19 | )% | ||||||||||||||||
|
Other Operating Segments (8)(9)
|
43,179 | 34,120 | 68,572 | 9,059 | 27 | % | (34,452 | ) | (50 | )% | ||||||||||||||||||
|
Other reconciling items(11)
|
(105,393 | ) | (196,844 | ) | (167,831 | ) | 91,451 | 46 | % | (29,013 | ) | (17 | )% | |||||||||||||||
|
Total
|
$ | 655,433 | $ | 421,904 | $ | 1,098,512 | $ | 233,529 | 55 | % | $ | (676,608 | ) | (62 | %) | |||||||||||||
|
Interest expense
|
(273,044 | ) | (266,039 | ) | (196,718 | ) | (7,005 | ) | (3 | )% | (69,321 | ) | (35 | )% | ||||||||||||||
|
Investment income (loss)
|
7,648 | 25,599 | 21,412 | (17,951 | ) | (70 | )% | 4,187 | 20 | % | ||||||||||||||||||
|
Gains (losses) on sales and retirements of long-lived assets and
other income (expense), net
|
(47,060 | ) | (12,559 | ) | (15,829 | ) | (34,501 | ) | (275 | )% | 3,270 | 21 | % | |||||||||||||||
|
Impairments and other charges(12)
|
(260,931 | ) | (330,976 | ) | (176,123 | ) | 70,045 | 21 | % | (154,853 | ) | (88 | )% | |||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
82,046 | (162,071 | ) | 731,254 | 244,117 | 151 | % | (893,325 | ) | (122 | )% | |||||||||||||||||
|
Income tax expense (benefit)
|
(24,814 | ) | (133,803 | ) | 209,660 | 108,989 | 81 | % | (343,463 | ) | (164 | )% | ||||||||||||||||
|
Subsidiary preferred stock dividend
|
750 | — | — | 750 | 100 | % | — | — | ||||||||||||||||||||
|
Income (loss) from continuing operations, net of tax
|
106,110 | (28,268 | ) | 521,594 | 134,378 | 475 | % | (549,862 | ) | (105 | )% | |||||||||||||||||
|
Income (loss) from discontinued operations, net of tax
|
(11,330 | ) | (57,620 | ) | (41,930 | ) | 46,290 | 80 | % | (15,690 | ) | (37 | )% | |||||||||||||||
|
Net income (loss)
|
94,780 | (85,888 | ) | 479,664 | 180,668 | 210 | % | (565,552 | ) | (118 | )% | |||||||||||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
(85 | ) | 342 | (3,927 | ) | (427 | ) | (125 | )% | 4,269 | 109 | % | ||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | $ | (85,546 | ) | $ | 475,737 | $ | 180,241 | 211 | % | $ | (561,283 | ) | (118 | )% | ||||||||||||
33
Table of Contents
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Rig activity:
|
||||||||||||||||||||||||||||
|
Rig years: (13)
|
||||||||||||||||||||||||||||
|
U.S. Lower 48 Land Drilling
|
174.5 | 149.4 | 247.9 | 25.1 | 17 | % | (98.5 | ) | (40 | )% | ||||||||||||||||||
|
U.S. Offshore
|
9.4 | 11.0 | 17.6 | (1.6 | ) | (15 | )% | (6.6 | ) | (38 | )% | |||||||||||||||||
|
Alaska
|
7.4 | 10.0 | 10.9 | (2.6 | ) | (26 | )% | (0.9 | ) | (8 | )% | |||||||||||||||||
|
Canada
|
29.8 | 19.7 | 35.5 | 10.1 | 51 | % | (15.8 | ) | (45 | )% | ||||||||||||||||||
|
International(14)
|
97.8 | 100.2 | 120.5 | (2.4 | ) | (2 | )% | (20.3 | ) | (17 | )% | |||||||||||||||||
|
Total rig years
|
318.9 | 290.3 | 432.4 | 28.6 | 10 | % | (142.1 | ) | (33 | )% | ||||||||||||||||||
|
Rig hours: (15)
|
||||||||||||||||||||||||||||
|
U.S. Land Well-servicing
|
643,813 | 590,878 | 1,090,511 | 52,935 | 9 | % | (499,633 | ) | (46 | )% | ||||||||||||||||||
|
Canada Well-servicing
|
172,589 | 143,824 | 248,032 | 28,765 | 20 | % | (104,208 | ) | (42 | )% | ||||||||||||||||||
|
Total rig hours
|
816,402 | 734,702 | 1,338,543 | 81,700 | 11 | % | (603,841 | ) | (45 | )% | ||||||||||||||||||
| (1) | All information present the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia as discontinued operations. | |
| (2) | These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore. | |
| (3) | Includes operating results of the Superior Merger after September 10, 2010. | |
| (4) | Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $6.9 million, $9.7 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (5) | Represents our oil and gas exploration, development and production operations. Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(189.3) million and $(207.3) million for the years ended December 31, 2009 and 2008, respectively. | |
| (6) | Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $18.7 million, $(182.6) million and $(204.1) million for the years ended December 31, 2010, 2009 and 2008, respectively. Additional information is provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. — Financial Statements and Supplementary Data. | |
| (7) | Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations. | |
| (8) | Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $7.7 million, $17.5 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (9) | Represents the elimination of inter-segment transactions. | |
| (10) | Adjusted income (loss) derived from operating activities is computed by subtracting direct costs, general and administrative expenses, depreciation and amortization, and depletion expense from “Operating revenues” and then adding “Earnings (losses) from unconsolidated affiliates.” These amounts should not be used as a substitute for those amounts reported under GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income (loss) derived from operating activities, because it believes that these financial measures are an accurate reflection of our ongoing profitability. A reconciliation of this non-GAAP measure to income (loss) from continuing operations before income taxes, which is a GAAP measure, is provided within the above table. | |
| (11) | Represents the elimination of inter-segment transactions and unallocated corporate expenses. |
34
Table of Contents
| (12) | Represents impairments and other charges recorded during the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (13) | Excludes well-servicing rigs, which are measured in rig hours. Includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates. Rig years represent a measure of the number of equivalent rigs operating during a given period. For example, one rig operating 182.5 days during a 365-day period represents 0.5 rig years. | |
| (14) | International rig years include our equivalent percentage ownership of rigs owned by unconsolidated affiliates which totaled 2.2 years, 2.5 years and 3.5 years during the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (15) | Rig hours represents the number of hours that our well-servicing rig fleet operated during the year. |
Segment
Results of Operations
Contract
Drilling
Our Contract Drilling operating segments contain one or more of
the following operations: drilling, workover and well-servicing
and pressure pumping, on land and offshore.
U.S. Lower 48 Land Drilling.
The results
of operations for this reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Operating revenues
|
$ | 1,294,853 | $ | 1,082,531 | $ | 1,878,441 | $ | 212,322 | 20 | % | $ | (795,910 | ) | (42 | )% | |||||||||||||
|
Adjusted income derived from operating activities
|
$ | 274,215 | $ | 294,679 | $ | 628,579 | $ | (20,464 | ) | (7 | )% | $ | (333,900 | ) | (53 | )% | ||||||||||||
|
Rig years
|
174.5 | 149.4 | 247.9 | 25.1 | 17 | % | (98.5 | ) | (40 | )% | ||||||||||||||||||
Operating revenues increased from 2009 to 2010 primarily due to
higher average dayrates and utilization. The increase was
partially offset by the decrease in early contract termination
revenue. Operating revenues related to early contract
termination during 2010 included $23.2 million as compared
to $108.5 million in 2009.
Adjusted income derived from operating activities decreased from
2009 to 2010 due to an increase in operating costs associated
with the increased drilling activity. Operating results
continued to be negatively impacted by higher depreciation
expense related to capital expansion projects completed in
recent years.
Operating results decreased from 2008 to 2009 primarily due to a
decline in drilling activity, driven by lower natural gas prices
beginning in the fourth quarter of 2008 and diminished demand as
customers released rigs and delayed drilling projects in
response to the significant drop in natural gas prices and the
tightening of the credit markets.
U.S. Land Well-servicing.
The results of
operations for this reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Operating revenues
|
$ | 444,665 | $ | 412,243 | $ | 758,510 | $ | 32,422 | 8 | % | $ | (346,267 | ) | (46 | )% | |||||||||||||
|
Adjusted income derived from operating activities
|
$ | 31,597 | $ | 28,950 | $ | 148,626 | $ | 2,647 | 9 | % | $ | (119,676 | ) | (81 | )% | |||||||||||||
|
Rig hours
|
643,813 | 590,878 | 1,090,511 | 52,935 | 9 | % | (499,633 | ) | (46 | )% | ||||||||||||||||||
Operating results increased from 2009 to 2010 primarily due to
an increase in rig utilization driven by higher oil prices. The
increase in operating results also reflects lower general and
administrative costs and depreciation expense.
Operating results decreased from 2008 to 2009 primarily due to
lower rig utilization and price erosion, driven by lower
customer demand for our services due to relatively lower oil
prices caused by the
35
Table of Contents
U.S. economic recession and reduced end product demand.
Operating results were further negatively impacted by higher
depreciation expense related to capital expansion projects
completed in recent years.
Pressure Pumping.
The results of operations
for this reportable segment were as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Operating revenues
|
$ | 321,295 | $ | — | $ | — | $ | 321,295 | 100 | % | $ | — | — | |||||||||||||||
|
Adjusted income derived from operating activities
|
$ | 66,651 | $ | — | $ | — | $ | 66,651 | 100 | % | $ | — | — | |||||||||||||||
Operating results reflecting our acquisition of Superior are
presented above for the period September 10, 2010 through
December 31, 2010. See Note 7 — Acquisitions
and Divestitures in Part II, Item 8. — Financial
Statements and Supplementary Data.
U.S. Offshore.
The results of operations
for this reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Operating revenues
|
$ | 123,761 | $ | 157,305 | $ | 252,529 | $ | (33,544 | ) | (21 | )% | $ | (95,224 | ) | (38 | )% | ||||||||||||
|
Adjusted income derived from operating activities
|
$ | 9,245 | $ | 30,508 | $ | 59,179 | $ | (21,263 | ) | (70 | )% | $ | (28,671 | ) | (48 | )% | ||||||||||||
|
Rig years
|
9.4 | 11.0 | 17.6 | (1.6 | ) | (15 | )% | (6.6 | ) | (38 | )% | |||||||||||||||||
The decrease in operating results from 2009 to 2010 primarily
resulted from receiving standby rates and lower utilization for
the
MODS
®
rigs,
SuperSundowner
tm
platform rigs and
Sundowner
®
platform rigs. Drilling activities significantly declined as our
customers suspended their operations in the Gulf of Mexico,
largely as a result of their inability to procure government
permits.
The decrease in operating results from 2008 to 2009 primarily
resulted from lower average dayrates and utilization for the
SuperSundowner
tm
platform rigs, workover
jack-up
rigs, barge drilling and workover rigs, and
Sundowner
®
platform rigs, partially offset by higher utilization of our
MODS
®
rigs inclusive of a significant term contract for a
MODS
®
rig deployed in January 2009.
Alaska.
The results of operations for this
reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Operating revenues and Earnings from unconsolidated affiliates
|
$ | 179,218 | $ | 204,407 | $ | 184,243 | $ | (25,189 | ) | (12 | )% | $ | 20,164 | 11 | % | |||||||||||||
|
Adjusted income derived from operating activities
|
$ | 51,896 | $ | 62,742 | $ | 52,603 | $ | (10,846 | ) | (17 | )% | $ | 10,139 | 19 | % | |||||||||||||
|
Rig years
|
7.4 | 10.0 | 10.9 | (2.6 | ) | (26 | )% | (0.9 | ) | (8 | %) | |||||||||||||||||
The decrease in operating results from 2009 to 2010 was
primarily due to lower average dayrates and drilling activity.
While drilling activity levels decreased significantly during
2010, operating results decreased only slightly due to an
acceleration of deferred revenues from a significant terminating
contract.
The increase in operating results from 2008 to 2009 was
primarily due to increases in average dayrates and drilling
activity. Although drilling activity levels decreased slightly
during 2009, operating results reflect the higher average
margins as a result of the addition of some high specification
rig work. The increase during 2009 was partially offset by
higher operating costs and increased depreciation expense as
well as increased labor and repair and maintenance costs in 2009
as compared to 2008.
36
Table of Contents
Canada.
The results of operations for this
reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||||||
|
Operating revenues and Earnings from unconsolidated affiliates
|
$ | 389,229 | $ | 298,653 | $ | 502,695 | $ | 90,576 | 30 | % | $ | (204,042 | ) | (41 | )% | |||||||||||||||||
|
Adjusted income (loss) derived from operating activities
|
$ | 22,970 | $ | (7,019 | ) | $ | 61,040 | $ | 29,989 | 427 | % | $ | (68,059 | ) | (111 | )% | ||||||||||||||||
|
Rig years — Drilling
|
29.8 | 19.7 | 35.5 | 10.1 | 51 | % | (15.8 | ) | (45 | )% | ||||||||||||||||||||||
|
Rig hours — Well-servicing
|
172,589 | 143,824 | 248,032 | 28,765 | 20 | % | (104,208 | ) | (42 | %) | ||||||||||||||||||||||
Operating results increased from 2009 to 2010 primarily as a
result of an overall increase in drilling and well-servicing
activity, which offset the decline in average drilling dayrates
and well-servicing hourly rates. The increased drilling activity
in Western Canada is the result of renewed interest in oil
exploration supported by sustained improved oil prices. The
well-servicing hourly rate decreased during 2010 as a result of
customer discounts to maintain market share. Our operating
results were also positively impacted during 2010 by cost
reduction efforts, mainly in general and administrative expenses.
Operating results decreased from 2008 to 2009 primarily as a
result of an overall decrease in drilling and well-servicing
activity due to lower natural gas prices driving a significant
decline of customer demand for drilling and well-servicing
operations. Our operating results for 2009 were further
negatively impacted by the economic uncertainty in the Canadian
drilling market and financial market instability. The Canadian
dollar began 2009 in a weak position versus the
U.S. dollar, during a period of time when drilling and
well-servicing activity was typically at its seasonal peak,
which also had an overall negative impact on operating results.
These decreases in operating results were partially offset by
cost reductions in direct costs, general and administrative
expenses and depreciation.
International.
The results of operations for
this reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages and rig activity) | ||||||||||||||||||||||||||||
|
Operating revenues and Earnings from unconsolidated affiliates
|
$ | 1,093,608 | $ | 1,265,097 | $ | 1,372,168 | $ | (171,489 | ) | (14 | )% | $ | (107,071 | ) | (8 | )% | ||||||||||||
|
Adjusted income derived from operating activities
|
$ | 254,744 | $ | 365,566 | $ | 407,675 | $ | (110,822 | ) | (30 | )% | $ | (42,109 | ) | (10 | )% | ||||||||||||
|
Rig years
|
97.8 | 100.2 | 120.5 | (2.4 | ) | (2 | )% | (20.3 | ) | (17 | )% | |||||||||||||||||
The decrease in operating results from 2009 to 2010 resulted
primarily from
year-over-year
decreases in average dayrates and lower utilization of rigs in
Saudi Arabia, Mexico, Kazakhstan, and Oman, driven by changes in
our customers’ drilling programs and longer lead times for
formalization of project requirements in our key markets.
Operating results were further negatively impacted by higher
depreciation expense related to capital expansion projects
completed in recent years.
The decrease in operating results from 2008 to 2009 resulted
primarily from
year-over-year
decreases in average dayrates and lower utilization of rigs in
Mexico, Libya, Argentina and Colombia, driven by weakening
customer demand for drilling services stemming from the drop in
oil prices in the fourth quarter of 2008 which continued
throughout 2009. Operating results were further negatively
impacted by higher depreciation expense related to capital
expansion projects completed in recent years. These decreases
were partially offset by higher average dayrates from two
jack-up
rigs
deployed in Saudi Arabia, increases in average dayrates for our
new and incremental rigs added and deployed during 2008 and a
start-up
floating, drilling, production, storage and offloading vessel
off the coast of the Republic of the Congo.
37
Table of Contents
Oil and Gas.
The results of operations for
this reportable segment are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Operating revenues and Earnings (losses) from unconsolidated
affiliates
|
$ | 40,611 | $ | (158,780 | ) | $ | (118,533 | ) | $ | 199,391 | 126 | % | $ | (40,247 | ) | (34 | )% | |||||||||||
|
Adjusted income (loss) derived from operating activities
|
$ | 6,329 | $ | (190,798 | ) | $ | (159,931 | ) | $ | 197,127 | 103 | % | $ | (30,867 | ) | (19 | )% | |||||||||||
Our operating results increased from 2009 to 2010 primarily
because our unconsolidated U.S. oil and gas joint venture
recorded a full-cost ceiling test writedown during 2009, of
which our proportionate share totaled $189.3 million. Our
proportionate share of the full-cost ceiling writedowns recorded
by our other unconsolidated oil and gas joint ventures, SMVP and
Remora, have been reclassified to discontinued operations. These
writedowns resulted from the application of the full-cost method
of accounting for costs related to oil and natural gas
properties. The full-cost ceiling test limits the carrying value
of the capitalized cost of the properties to the present value
of future net revenues attributable to proved oil and natural
gas reserves, discounted at 10%, plus the lower of cost or
market value of unproved properties. The full-cost ceiling test
was evaluated using the
12-month
average commodity price as required by the revised SEC rules.
Operating results for our U.S. oil and gas joint venture,
excluding the full-cost ceiling test writedown, improved from
2009 to 2010.
Our operating results decreased from 2008 to 2009 primarily as a
result of the full-cost ceiling test writedown recorded during
2009 discussed above. Operating results further decreased from
2008 to 2009 due to declines in natural gas prices and
production volumes. Additionally, operating results for 2008
included a $12.3 million gain recorded on the sale of
leasehold interests.
Additional information is provided in Notes 21 —
Discontinued Operations and 24 — Supplemental
Information on Oil and Gas Exploration and Production Activities
in Part II, Item 8. — Financial Statements
and Supplementary Data.
Other
Operating Segments
These operations include our drilling technology and top-drive
manufacturing, directional drilling, rig instrumentation and
software, and construction and logistics operations. The results
of operations for these operating segments are as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Operating revenues and Earnings from unconsolidated affiliates
|
$ | 456,893 | $ | 446,282 | $ | 683,186 | $ | 10,611 | 2 | % | $ | (236,904 | ) | (35 | )% | |||||||||||||
|
Adjusted income derived from operating activities
|
$ | 43,179 | $ | 34,120 | $ | 68,572 | $ | 9,059 | 27 | % | $ | (34,452 | ) | (50 | %) | |||||||||||||
The increase in operating results from 2009 to 2010 primarily
resulted from higher demand in the United States and Canada
drilling markets for rig instrumentation and data collection
services from oil and gas exploration companies and higher
third-party rental and rigwatch units, which generate higher
margins, partially offset by a continued decline in customer
demand for our construction and logistics services in Alaska.
The decreases in operating results from 2008 to 2009 primarily
resulted from (i) lower demand in the U.S. and Canada
drilling markets for rig instrumentation and data collection
services from oil and gas exploration companies,
(ii) decreases in customer demand for our construction and
logistics services in Alaska and (iii) decreased capital
equipment unit volumes and lower service and rental activity as
a result of the slowdown in the oil and gas industry.
38
Table of Contents
Discontinued
Operations
During 2010, we began actively marketing our oil and gas assets
in the Horn River basin in Canada and in the Llanos basin in
Colombia. These assets also include our 49.7% and 50.0%
ownership interests in our investments of Remora and SMVP,
respectively, which we account for using the equity method of
accounting. All of these assets are included in our oil and gas
operating segment. We determined that the plan of sale criteria
in the ASC Topic relating to the Presentation of Financial
Statements for Assets Sold or Held for Sale had been met during
the third quarter of 2010. Accordingly, we reclassified these
wholly owned oil and gas assets from our property, plant and
equipment, net, as well as our investment balances for Remora
and SMVP from investments in unconsolidated affiliates to assets
held for sale in our consolidated balance sheet at
September 30, 2010.
The operating results from these assets for all periods
presented are retroactively presented and accounted for as
discontinued operations in the accompanying audited consolidated
statements of income (loss). Our condensed statements of income
(loss) from discontinued operations for the years ended
December 31, 2010, 2009 and 2008 were as follows:
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Revenues
|
$ | 37,840 | $ | 8,937 | $ | 4,354 | $ | 28,903 | 323 | % | $ | 4,583 | 105 | % | ||||||||||||||
|
Earnings (losses) from unconsolidated affiliates(1)
|
$ | (10,628 | ) | $ | (59,248 | ) | $ | (37,286 | ) | $ | 48,620 | 82 | % | $ | (21,962 | ) | (59 | )% | ||||||||||
|
Income (loss) from discontinued operations, net of tax
|
||||||||||||||||||||||||||||
|
Income (loss) from discontinued operations, net of tax
|
$ | (11,330 | ) | $ | (57,620 | ) | $ | (41,930 | ) | $ | 46,290 | 80 | % | $ | (15,690 | ) | (37 | )% | ||||||||||
| (1) | Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million and $21.0 million, for the years ended December 31, 2009 and 2008, respectively. |
OTHER
FINANCIAL INFORMATION
General
and administrative expenses
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
General and administrative expenses
|
$ | 346,661 | $ | 428,161 | $ | 479,194 | $ | (81,500 | ) | (19 | )% | $ | (51,033 | ) | (11 | )% | ||||||||||||
|
General and administrative expenses as a percentage of operating
revenues
|
8.3 | % | 11.6 | % | 8.7 | % | (3.3 | )% | (28 | )% | 2.9 | % | 33 | % | ||||||||||||||
General and administrative expenses decreased from 2009 to 2010
and from 2008 to 2009 primarily as a result of significant
decreases in wage-related expenses and other cost-reduction
efforts across all business units. The decrease during 2009 was
partially offset by share-based compensation expense, which
included $72.1 million of compensation expense related to
previously granted restricted stock and option awards held by
Messrs. Isenberg and Petrello that was unrecognized as of
April 1, 2009. The recognition of this expense resulted
from provisions of their respective new employment agreements
that effectively eliminated the risk of forfeiture of such
awards. There is no remaining unrecognized expense related to
their outstanding restricted stock and option awards. Excluding
the share-based compensation expense related to the previous
awards held by Messrs. Isenberg and Petrello, general and
administrative expenses for 2009 and 2010 are substantially
below 2008 levels, indicating that the cost-reduction efforts
and actions across all business units beginning in late 2008
have had a favorable impact on our operating results.
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Depreciation
and amortization, and depletion expense
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Depreciation and amortization expense
|
$ | 764,253 | $ | 667,100 | $ | 614,367 | $ | 97,153 | 15 | % | $ | 52,733 | 9 | % | ||||||||||||||
|
Depletion expense
|
$ | 17,943 | $ | 9,417 | $ | 22,308 | $ | 8,526 | 91 | % | $ | (12,891 | ) | (58 | )% | |||||||||||||
Depreciation and amortization
expense.
Depreciation and amortization expense
increased from 2009 to 2010 and from 2008 to 2009 primarily as a
result of projects completed in recent years under our expanded
capital expenditure program that commenced in early 2005.
Depletion expense.
Depletion expense increased
from 2009 to 2010 as a result of increased
units-of-production
depletion. Depletion expense decreased from 2008 to 2009
primarily as a result of decreased natural gas production
volumes during each year.
Interest
expense
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Interest expense
|
$ | 273,044 | $ | 266,039 | $ | 196,718 | $ | 7,005 | 3 | % | $ | 69,321 | (35 | %) | ||||||||||||||
Interest expense increased from 2009 to 2010 as a result of the
interest expense related to our September 2010 issuance of
5.0% senior notes due September 2020. The increase was
partially offset by a reduction to interest expense resulting
from our repurchases of approximately $1.2 billion par
value of 0.94% senior exchangeable notes during 2009 and
2010.
Interest expense increased from 2008 to 2009 as a result of the
interest expense related to our January 2009 issuance of
9.25% senior notes due January 2019. The increase was
partially offset by a reduction to interest expense due to our
repurchases of approximately $1.1 billion par value of
0.94% senior exchangeable notes during 2008 and 2009.
Investment
income (loss)
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Investment income (loss)
|
$ | 7,648 | $ | 25,599 | $ | 21,412 | $ | (17,951 | ) | (70 | )% | $ | 4,187 | 20 | % | |||||||||||||
Investment income during 2010 was $7.6 million compared to
$25.6 million during the prior year. Investment income in
2010 included interest and dividend income of $7.2 million
from our cash, other short-term and long-term investments and
$4.9 million from gains on sales of short-term and
long-term investments, partially offset by net unrealized losses
of $4.4 million from our trading securities.
Investment income during 2009 was $25.6 million compared to
$21.4 million during 2008. Investment income in 2009
included net unrealized gains of $9.8 million from our
trading securities and interest and dividend income of
$15.9 million from our cash, other short-term and long-term
investments.
Investment income during 2008 was $21.4 million and
included net unrealized gains of $8.5 million from our
trading securities and interest and dividend income of
$40.5 million from our short-term and long-term
investments, partially offset by losses of $27.4 million
from our actively managed funds classified as long-term
investments.
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Table of Contents
Gains
(losses) on sales and retirements of long-lived assets and other
income (expense), net
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Gains (losses) on sales and retirements of long-lived assets and
other income (expense), net
|
$ | (47,060 | ) | $ | (12,559 | ) | $ | (15,829 | ) | $ | (34,501 | ) | (275 | )% | $ | 3,270 | 21 | % | ||||||||||
The amount of gains (losses) on sales and retirements of
long-lived assets and other income (expense), net for 2010
represents a net loss of $47.1 million and includes:
(i) foreign currency exchange losses of approximately
$17.9 million, (ii) litigation expenses of
$6.4 million, (iii) net losses on sales and
retirements of long-lived assets of approximately
$6.6 million, (iv) acquisition-related costs of
$7.0 million and (v) losses of $7.0 million
recognized on purchases of our 0.94% senior exchangeable
notes due 2011.
The amount of gains (losses) on sales and retirements of
long-lived assets and other income (expense), net for 2009
represents a net loss of $12.6 million and includes:
(i) foreign currency exchange losses of approximately
$8.4 million, (ii) litigation expenses of
$11.5 million and (iii) net losses on sales and
retirements of long-lived assets of approximately
$5.9 million. These losses were partially offset by pre-tax
gains of $11.5 million recognized on purchases of
$964.8 million par value of our 0.94% senior
exchangeable notes due 2011.
The amount of gains (losses) on sales and retirements of
long-lived assets and other income (expense), net for 2008
represents a net loss of $15.8 million and includes:
(i) losses on derivative instruments of approximately
$14.6 million, including a $9.9 million loss on a
three-month written put option and a $4.7 million loss on
the fair value of our range-cap-and-floor derivative,
(ii) losses on retirements on long-lived assets of
approximately $13.2 million, inclusive of involuntary
conversion losses on long-lived assets of approximately
$12.0 million, net of insurance recoveries, related to
damage sustained from Hurricanes Gustav and Ike during 2008 and
(iii) litigation expenses of $3.5 million. These
losses were partially offset by a $12.2 million pre-tax
gain recognized on our purchase of $100 million par value
of 0.94% senior exchangeable notes due 2011.
Impairments
and Other Charges
| Year Ended December 31, | Increase/(Decrease) | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 to 2009 | 2009 to 2008 | ||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||
|
Impairment of oil and gas- related assets
|
$ | 192,179 | $ | 197,744 | $ | 21,537 | $ | (5,565 | ) | (3 | )% | $ | 176,207 | 818 | % | |||||||||||||
|
Impairment of long-lived assets
|
58,045 | 64,229 | — | (6,184 | ) | (10 | )% | 64,229 | 100 | % | ||||||||||||||||||
|
Goodwill impairments
|
10,707 | 14,689 | 150,008 | (3,982 | ) | (27 | )% | (135,319 | ) | (90 | )% | |||||||||||||||||
|
Impairment of other intangible assets
|
— | — | 4,578 | — | — | (4,578 | ) | (100 | )% | |||||||||||||||||||
|
Other-than-temporary
impairment on securities
|
— | 54,314 | — | (54,314 | ) | (100 | )% | 54,314 | 100 | % | ||||||||||||||||||
|
Total
|
$ | 260,931 | $ | 330,976 | $ | 176,123 | $ | (70,045 | ) | (21 | )% | $ | 154,853 | 88 | % | |||||||||||||
Impairments
of Oil and Gas Assets
In 2010, we recognized impairments of $192.2 million
related to our oil and gas assets. Of this total,
$137.8 million represents writedowns to the carrying value
of some acreage in the United States, which we do not have
future plans to develop due to the sustained low natural gas
prices, and certain exploratory wells in Colombia, which we have
determined will be uneconomical to develop in the foreseeable
future.
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The remaining $54.3 million relates to an impairment of a
financing receivable as a result of the continued commodity
price deterioration in the Barnett Shale area of north central
Texas. We determined that this impairment was necessary using
estimates and assumptions based on estimated cash flows for
proved and probable reserves and current natural gas prices. We
believe the estimates used provide a reasonable estimate of
current fair value. We determined that this represented a
Level 3 fair value measurement. As of December 31,
2010, the carrying value of this oil and gas financing
receivable, which is included in long-term investments, has been
reduced to $20.1 million. A further protraction or
continued period of lower commodity prices could result in
recognition of future impairment charges.
In 2009, we recorded impairments totaling $197.7 million to
some of our wholly owned oil and gas assets. We recognized an
impairment of $149.1 million to a financing receivable as a
result of commodity price deterioration and the lower price
environment last longer than expected. The prolonged period of
lower prices significantly reduced demand for future gas
production and development in the Barnett Shale area of north
central Texas and influenced our decision not to expend capital
to develop on some of the undeveloped acreage. The impairment,
which represented a Level 3 fair value measurement, was
determined using discounted cash flow models involving
assumptions based on estimated cash flows for proved and
probable reserves, undeveloped acreage value, and current and
expected natural gas prices. Additionally, our annual impairment
tests on our U.S. wholly owned oil and gas properties
resulted in impairment charges of $48.6 million to
writedown the carrying value of some acreage that we do not have
future plans to develop.
In 2008, our annual impairment tests on our U.S. wholly
owned oil and gas properties resulted in impairment charges of
$21.5 million primarily due to the significant decline in
oil and natural gas prices at the end of 2008. Additional
discussion of our policy pertaining to the calculation of our
annual impairment tests is set forth below in “Oil and Gas
Properties” and in Note 2 — Summary of
Significant Accounting Policies in Part II,
Item 8. — Financial Statements and Supplementary
Data.
Impairments
of Long-Lived Assets
In 2010, we recognized impairments of $58.0 million in
multiple operating segments. These impairments included
$23.2 million related to the retirement of certain rig
components, comprised of engines, top-drive units, building
modules and other equipment that has become obsolete or
inoperable in each of these operating segments in our
U.S. Lower 48 Land Drilling, U.S. Land Well-servicing
and U.S. Offshore Contract Drilling segment. The impairment
charges were determined to be necessary as a result of the
continued lower commodity price environment and its related
impact on drilling and well-servicing activity and our dayrates.
A prolonged period of legislative uncertainty in our U.S.
Offshore operations, or continued period of lower natural gas
and oil prices and its potential impact on our utilization and
dayrates could result in the recognition of future impairment
charges to additional assets if future cash flow estimates,
based upon information then available to management, indicate
that the carrying value of those assets may not be recoverable.
The remaining $34.8 million in impairment charges recorded
during 2010 include $27.3 million related to the impairment
of some
jack-up
rigs
in our U.S. Offshore operating segment and
$7.5 million to our aircraft and some drilling equipment in
Nabors Blue Sky Ltd. These impairment charges stemmed from our
annual impairment tests on long-lived assets, which determined
that the sum of the estimated future cash flows, on an
undiscounted basis, was less than the carrying amount of these
assets. The estimated fair values of these assets were
calculated using discounted cash flow models involving
assumptions based on our utilization of the assets, revenues as
well as direct costs, capital expenditures and working capital
requirements. The impairment charge relating to our
U.S. Offshore segment was deemed necessary due to the
economic conditions for drilling in the Gulf of Mexico, as
discussed below. The impairment charge relating to Nabors Blue
Sky Ltd. was deemed necessary due to the continued duration of
the downturn in the oil and gas industry in Canada, which has
resulted in diminished demand for the remote access services
provided by this subsidiary’s aircraft fleet.
In 2009, we recognized impairments of $64.2 million related
to retirements of certain assets in our U.S. Offshore,
Alaska, Canada and International Contract Drilling segments,
which reduced their aggregate carrying value to their estimated
aggregate salvage value. The retirements included inactive
workover
jack-up
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rigs in our U.S. Offshore and International operations, the
structural frames of some incomplete coiled tubing rigs in our
Canada operations and miscellaneous rig components in our Alaska
operations. The impairment charges resulted from the continued
deterioration and
longer-than-expected
downturn in the demand for oil and gas drilling activities.
Goodwill
Impairments
In 2010, we recognized an impairment of approximately
$10.7 million relating to our goodwill balance of our
U.S. Offshore operating segment. The impairment charge
stemmed from our annual impairment test on goodwill, which
compared the estimated fair value of each of our reporting units
to its carrying value. The estimated fair value of our
U.S. Offshore segment was determined using discounted cash
flow models involving assumptions based on our utilization of
rigs and revenues as well as direct costs, general and
administrative costs, depreciation, applicable income taxes,
capital expenditures and working capital requirements. We
determined that the fair value estimated for purposes of this
test represented a Level 3 fair value measurement. The
impairment charge was deemed necessary due to the uncertainty of
utilization of some of our rigs as a result of changes in our
customers’ plans for future drilling operations in the Gulf
of Mexico. Many of our customers have suspended drilling
operations in the Gulf of Mexico, largely as a result of their
inability to obtain government permits. Although the
U.S. deepwater drilling moratorium has been lifted, it is
uncertain whether our customers’ ability to obtain
government permits will improve in the near term. A
significantly prolonged period of lower oil and natural gas
prices or changes in laws and regulations could adversely affect
the demand for and prices of our services, which could result in
future goodwill impairment charges for other reporting units due
to the potential impact on our estimate of our future operating
results. See Critical Accounting Policies below and Note 2
— Summary of Significant Accounting Policies (included
under the caption “Goodwill”) in Part II,
Item 8. — Financial Statements and Supplementary
Data.
In 2009, we impaired the remaining goodwill balance of
$14.7 million of Nabors Blue Sky Ltd., one of our Canadian
subsidiaries who provides access to remote drilling sites by
helicopters and fixed-wing aircraft. The impairment charges
resulted from our annual impairment tests on goodwill which
compared the estimated fair value of each of our reporting units
to its carrying value. The estimated fair value of these
business units was determined using discounted cash flow models
involving assumptions based on our utilization of rigs or
aircraft, revenues and earnings from affiliates, as well as
direct costs, general and administrative costs, depreciation,
applicable income taxes, capital expenditures and working
capital requirements. We determined that the fair value
estimated for purposes of this test represented a Level 3
fair value measurement. The impairment charges were deemed
necessary due to the continued downturn in the oil and gas
industry in Canada and the lack of certainty regarding eventual
recovery in the value of these operations. This downturn led to
reduced capital spending by some of our customers and diminished
demand for our drilling services and for immediate access to
remote drilling sites.
In 2008, we impaired the entire goodwill balance of
$145.4 million of our Canada Well-servicing and Drilling
operating segment and recorded an impairment of
$4.6 million to Nabors Blue Sky Ltd. This impairment was
also deemed necessary due to the continued downturn in the oil
and gas industry in Canada and the lack of certainty regarding
eventual recovery in the value of these operations. This
downturn led to reduced capital spending by some of our
customers and diminished demand for our drilling services and
for immediate access to remote drilling sites.
Other
than Temporary Impairments on Debt and Equity
Securities
In 2009, we recorded
other-than-temporary
impairments to our
available-for-sale
securities totaling $54.3 million. Of this,
$35.6 million was related to an investment in a corporate
bond that was downgraded to non-investment grade level by
Standard and Poor’s and Moody’s Investors Service
during the year. Our determination that the impairment was
other-than-temporary was based on a variety of factors,
including the length of time and extent to which the market
value had been less than cost, the financial condition of the
issuer of the security, and the credit ratings and recent
reorganization of the issuer.
The remaining $18.7 million related to an equity security
of a public company whose operations are driven in large measure
by the price of oil and in which we invested approximately
$46 million during the
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second and third quarters of 2008. During late 2008, demand for
oil and gas began to diminish significantly as part of the
general deterioration of the global economic environment,
causing a broad decline in value of nearly all oil and
gas-related equity securities. Because the trading price per
share of this security remained below our cost basis for an
extended period of time, we determined the investment was other
than temporarily impaired and it was appropriate to write down
its carrying value to its estimated fair value.
Income
tax rate
| Increase/(Decrease) | ||||||||||||||||||||||||||||
| Year Ended December 31, |
2010 to
|
2009 to
|
||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
|
Effective income tax rate from continuing operations
|
(30 | )% | 83 | % | 29 | % | (113 | )% | (136 | )% | 54 | % | 186 | % | ||||||||||||||
Our effective income tax rate for 2010 and 2009 reflects the
disparity between losses in our U.S. operations
(attributable primarily to impairments) and income in our other
operations primarily in lower tax jurisdictions. Because the
U.S. income tax rate is higher than that of other
jurisdictions, the tax benefit from our U.S. losses was not
proportionately reduced by the tax expense from our other
operations. During 2010 and 2009, the result was a net tax
benefit. In 2009, that benefit represented a significant
percentage of our consolidated loss from continuing operations
before income taxes. Because of the manner in which that number
was derived, we do not believe it presents a meaningful basis
for comparing our 2009 effective income tax rate to either the
2010 or 2008 effective income tax rate.
We are subject to income taxes in the United States and numerous
other jurisdictions. Significant judgment is required in
determining our worldwide provision for income taxes. One of the
most volatile factors in this determination is the relative
proportion of our income or loss being recognized in high-
versus low-tax jurisdictions. In the ordinary course of our
business, there are many transactions and calculations for which
the ultimate tax determination is uncertain. We are regularly
audited by tax authorities. Although we believe our tax
estimates are reasonable, the final outcome of tax audits and
any related litigation could be materially different than what
is reflected in our income tax provisions and accruals. The
results of an audit or litigation could materially affect our
financial position, income tax provision, net income, or cash
flows.
Various bills have been introduced in Congress that could reduce
or eliminate the tax benefits associated with our reorganization
as a Bermuda company. Legislation enacted by Congress in 2004
provides that a corporation that reorganized in a foreign
jurisdiction on or after March 4, 2003 be treated as a
domestic corporation for U.S. federal income tax purposes.
Nabors’ reorganization was completed June 24, 2002.
There have been and we expect that there may continue to be
legislation proposed by Congress from time to time which, if
enacted, could limit or eliminate the tax benefits associated
with our reorganization.
Because we cannot predict whether legislation will ultimately be
adopted, no assurance can be given that the tax benefits
associated with our reorganization will ultimately accrue to the
benefit of the Company and its shareholders. It is possible that
future changes to the tax laws (including tax treaties) could
impact our ability to realize the tax savings recorded to date
as well as future tax savings resulting from our reorganization.
Liquidity
and Capital Resources
Cash
Flows
Our cash flows depend, to a large degree, on the level of
spending by oil and gas companies for exploration, development
and production activities. Sustained increases or decreases in
the price of natural gas or oil could have a material impact on
these activities, and could also materially affect our cash
flows. Certain sources and uses of cash, such as the level of
discretionary capital expenditures, purchases and sales of
investments, issuances and repurchases of debt and of our common
shares are within our control and are adjusted as necessary
based on market conditions. The following is a discussion of our
cash flows for the years ended December 31, 2010 and 2009.
Operating Activities.
Net cash provided by
operating activities totaled $1.1 billion during 2010
compared to net cash provided by operating activities of
$1.6 billion during 2009. Net cash provided by
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operating activities (“operating cash flows”) is our
primary source of capital and liquidity. Factors affecting
changes in operating cash flows are largely the same as those
that affect net earnings, with the exception of non-cash
expenses such as depreciation and amortization, depletion,
impairments, share-based compensation, deferred income taxes and
our proportionate share of earnings or losses from
unconsolidated affiliates. Net income (loss) adjusted for
non-cash components was approximately $1.3 billion and
$1.1 billion for the years ended December 31, 2010 and
2009, respectively. Additionally, changes in working capital
items such as collection of receivables can be a significant
component of operating cash flows. Changes in working capital
items used $202.4 million in cash flows for the year ended
December 31, 2010 and provided $471.9 million in cash
flows for the year ended December 31, 2009.
Investing Activities.
Net cash used for
investing activities totaled $1.7 billion during 2010
compared to net cash used for investing activities of
$1.2 billion during 2009. During 2010, we used cash of
$680.2 million and $53.4 million, respectively, to
acquire Superior (net of the cash acquired) and the assets of
Energy Contractors. During 2010 and 2009, we used cash primarily
for capital expenditures totaling $930.3 million and
$1.1 billion, respectively, and investments in
unconsolidated affiliates totaling $40.9 million and
$125.1 million, respectively. During 2009, we derived cash
from sales of investments, net of purchases, totaling
$24.4 million.
Financing Activities.
Net cash provided by
financing activities totaled $280.3 million during 2010
compared to net cash used for financing activities of
$19.4 million during 2009. During 2010, cash was provided
from the receipt of $682.3 million in proceeds, net of debt
issuance costs, from the September 2010 issuance of
5.0% senior notes due 2020. During 2010, we used cash to
purchase $273.9 million of our 0.94% senior
exchangeable notes due 2011 and to repay $124.0 million of
Superior’s revolving credit facility and second lien notes.
During 2009, cash was derived from the receipt of
$1.1 billion in proceeds, net of debt issuance costs, from
the January 2009 issuance of 9.25% senior notes due 2019,
and cash totaling $862.6 million was used to purchase
$964.8 million par value of 0.94% senior exchangeable
notes due 2011 and $225.2 million was used to redeem the
4.875% senior notes. During 2010 and 2009, cash was
provided by our receipt of proceeds totaling $8.2 million
and $11.2 million, respectively, from the exercise by our
employees of options to acquire our common shares.
Future
Cash Requirements
As of December 31, 2010, we had long-term debt, including
current maturities, of $4.4 billion and cash and
investments of $841.5 million, including $40.3 million
of long-term investments and other receivables. Long-term
investments and other receivables include $32.9 million in
oil and gas financing receivables.
As of December 31, 2010, the current portion of our
long-term debt included $1.4 billion par value of Nabors
Delaware’s 0.94% senior exchangeable notes that mature
in May 2011. We continue to assess our ability to meet this
obligation, along with our other operating and capital
requirements and other potential opportunities. We expect to do
so through a combination of cash on hand, future operating cash
flows, possible dispositions of non-core assets, availability
under our unsecured revolving credit facility and our ability to
access the capital markets, if required. At December 31, 2010,
we had $700 million available under a senior unsecured
revolving credit facility; in January 2011, we added another
lender to the facility raising the amount available to
$750 million. On February 11, 2011, one of our subsidiaries
established a credit facility, which we unconditionally
guarantee, for approximately US$50 million. There are
a number of factors that could negatively impact our plans,
including our ability to access the financial markets at
competitive rates if the financial markets are limited or
restricted, a decline in oil and natural gas prices, a decline
in demand for our services or market perceptions of us and our
industry.
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The senior exchangeable notes would require us upon exchange to
pay note holders cash up to the principal amount of the notes
and our common shares for any amount by which the exchange value
of the notes exceeds their principal amount. The notes can only
be exchanged:
(i) if our share price exceeds $59.57 (approximately) for
at least 20 trading days during the period of 30 consecutive
trading days ending on the last trading day of the previous
calendar quarter; or
(ii) during the five business days immediately following
any ten consecutive trading day period in which the per note
trading price for each day of that period is less than 95% of
the product of (a) the sale price of our common shares and
(b) the then applicable exchange rate for the notes; or
(iii) upon the occurrence of specified corporate
transactions.
On February 24, 2011, the closing market price for our
common stock was $27.65 per share. If any of the foregoing
conditions were met and the notes were exchanged at a price
equal to 100% of their principal amount before maturity, the
required cash payment could have a significant impact on our
level of cash and cash equivalents and investments available to
meet our other cash obligations. However, management believes
that if the price of our shares exceeded $59.57 for the required
period of time, note holders would be unlikely to exchange them
as it would be more beneficial to sell the notes to other
investors on the open market. Nevertheless, there can be no
assurance that the holders would not exchange the notes.
We expect capital expenditures over the next 12 months to
approximate $1.3-1.7 billion. We had outstanding purchase
commitments of approximately $754.6 million at
December 31, 2010, primarily for rig-related enhancements,
construction and sustaining capital expenditures and other
operating expenses. We can reduce the planned expenditures if
necessary, or increase them if market conditions and new
business opportunities warrant it.
We have historically completed a number of acquisitions and will
continue to evaluate opportunities to acquire assets or
businesses to enhance our operations. Several of our previous
acquisitions were funded through issuances of our common shares.
Future acquisitions may be paid for using existing cash or
issuing debt or Nabors shares. Such capital expenditures and
acquisitions will depend on our view of market conditions and
other factors.
See our discussion of guarantees issued by Nabors that could
have a potential impact on our financial position, results of
operations or cash flows in future periods included below under
Off-Balance Sheet Arrangements (Including Guarantees).
The following table summarizes our contractual cash obligations
as of December 31, 2010:
| Payments Due by Period | ||||||||||||||||||||
| Total | < 1 Year | 1-3 Years | 3-5 Years | Thereafter | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Contractual cash obligations:
|
||||||||||||||||||||
|
Long-term debt:(1)
|
||||||||||||||||||||
|
Principal
|
$ | 4,478,455 | $ | 1,403,455(2 | ) | $ | 275,000(3 | ) | $ | — | $ | 2,800,000(4 | ) | |||||||
|
Interest
|
1,720,577 | 220,434 | 412,942 | 398,076 | 689,125 | |||||||||||||||
|
Operating leases(5)
|
74,128 | 25,749 | 32,774 | 14,673 | 932 | |||||||||||||||
|
Capital leases
|
4,297 | 2,201 | 1,811 | 285 | ||||||||||||||||
|
Purchase commitments(6)
|
754,605 | 603,960 | 77,145 | 73,500 | — | |||||||||||||||
|
Employment contracts(5)
|
28,319 | 11,965 | 16,035 | 319 | — | |||||||||||||||
|
Pension funding obligations
|
1,315 | 1,315 | — | — | — | |||||||||||||||
|
Transportation and Processing Contracts(7)
|
400,037 | 29,564 | 120,344 | 128,252 | 121,877 | |||||||||||||||
|
Total contractual cash obligations
|
$ | 7,461,733 | $ | 2,298,643 | $ | 936,051 | $ | 615,105 | $ | 3,611,934 | ||||||||||
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The table above excludes liabilities for unrecognized tax
benefits totaling $124.1 million as of December 31,
2010 because we are unable to make reasonably reliable estimates
of the timing of cash settlements with the respective taxing
authorities. Further details on the unrecognized tax benefits
can be found in Note 12 — Income Taxes in
Part II, Item 8. — Financial Statements and
Supplementary Data.
(1) See Note 11 — Debt in Part II,
Item 8. — Financial Statements and Supplementary
Data.
| (2) | Includes the remaining portion of Nabors Delaware’s 0.94% senior exchangeable notes due May 2011. |
(3) Includes Nabors Delaware’s 5.375% senior
notes due August 2012.
| (4) | Represents Nabors Delaware’s aggregate 6.15% senior notes due February 2018, 9.25% senior notes due January 2019 and 5.0% senior notes due September 2020. | |
| (5) | See Note 17 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data. | |
| (6) | Purchase commitments include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including fixed or minimum quantities to be purchased; fixed, minimum or variable pricing provisions; and the approximate timing of the transaction. | |
| (7) | We have contracts with a pipeline company to pay specified fees based on committed volumes for gas transport and processing, as calculated on a monthly basis. Due to low natural gas prices and our decision to delay drilling, our current available production flowing to pipelines and processing plants does not meet the daily committed volumes required under the contracts. The amounts set forth in the table above reflect the aggregate fees payable under these contracts. |
We may from time to time seek to retire or purchase our
outstanding debt through cash purchases
and/or
exchanges for equity securities, both in open-market purchases,
privately negotiated transactions or otherwise. Such repurchases
or exchanges, if any, will depend on prevailing market
conditions, our liquidity requirements, contractual restrictions
and other factors. The amounts involved may be material.
In July 2006 our Board of Directors authorized a share
repurchase program under which we may repurchase up to
$500 million of our common shares in the open market or in
privately negotiated transactions. Through December 31,
2010, $464.5 million of our common shares had been
repurchased under this program. As of December 31, 2010, we
had the capacity to repurchase up to an additional
$35.5 million of our common shares under the July
2006 share repurchase program.
See Note 17 — Commitments and Contingencies in
Part II, Item 8. — Financial Statements and
Supplementary Data for discussion of commitments and
contingencies relating to (i) new employment agreements,
effective April 1, 2009, that could result in significant
cash payments of $100 million and $50 million to
Messrs. Isenberg and Petrello, respectively, by the Company
if their employment is terminated in the event of death or
disability or cash payments of $100 million to
Mr. Isenberg and a cash payment of approximately
$34 million to Mr. Petrello, respectively, by the
Company if their employment is terminated without cause or in
the event of a change in control and (ii) off-balance sheet
arrangements (including guarantees).
Financial
Condition and Sources of Liquidity
Our primary sources of liquidity are cash and cash equivalents,
short-term and long-term investments and cash generated from
operations. As of December 31, 2010, we had cash and
investments of $841.5 million (including $40.3 million
of long-term investments and other receivables, inclusive of
$32.9 million in oil and gas financing receivables) and
working capital of $458.6 million. Oil and gas financing
receivables are classified as long-term investments. These
receivables represent our financing agreements for certain
production payment contracts in our Oil and Gas segment. This
compares to cash and investments of $1.2 billion (including
$100.9 million of long-term investments and other
receivables, inclusive of $92.5 million in oil and gas
financing receivables) and working capital of $1.6 billion
as of December 31, 2009.
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Our gross funded debt to capital ratio was 0.42:1 as of
December 31, 2010 and 0.41:1 as of December 31, 2009.
Our net funded debt to capital ratio was 0.37:1 as of
December 31, 2010 and 0.33:1 as of December 31, 2009.
The gross funded debt to capital ratio is calculated by dividing
(x) funded debt by (y) funded debt
plus
deferred tax liabilities (net of deferred tax assets)
plus
capital. Funded debt is the sum of
(1) short-term borrowings, (2) the current portion of
long-term debt and (3) long-term debt. Capital is
shareholders’ equity.
The net funded debt to capital ratio is calculated by dividing
(x) net funded debt by (y) net funded debt
plus
deferred tax liabilities (net of deferred tax assets)
plus
capital. Net funded debt is funded debt
minus
the sum of cash and cash equivalents and short-term and
long-term investments and other receivables. Both of these
ratios are used to calculate a company’s leverage in
relation to its capital. Neither ratio measures operating
performance or liquidity as defined by GAAP and, therefore, may
not be comparable to similarly titled measures presented by
other companies.
Our interest coverage ratio was 7.0:1 as of December 31,
2010 and 6.3:1 as of December 31, 2009. The interest
coverage ratio is a trailing
12-month
quotient of the sum of income (loss) from continuing operations,
net of tax, net income (loss) attributable to noncontrolling
interest, interest expense, subsidiary preferred stock
dividends, depreciation and amortization, depletion expense,
impairments and other charges, income tax expense (benefit) and
our proportionate share of writedowns from our unconsolidated
oil and gas joint ventures
less
investment income (loss)
divided by cash interest expense plus subsidiary preferred stock
dividends. This ratio is a method for calculating the amount of
operating cash flows available to cover cash interest expense.
The interest coverage ratio is not a measure of operating
performance or liquidity defined by GAAP and may not be
comparable to similarly titled measures presented by other
companies.
During the third quarter of 2010, we and Nabors Delaware entered
into a credit agreement under which the lenders committed to
provide up to $700 million under an unsecured revolving
credit facility (the “Revolving Credit Facility”) or
the (“Facility”). The Facility also provides Nabors
Delaware the option to add other lenders and increase the
aggregate principal amount of commitments to $850 million
by adding new lenders to the Facility or by asking existing
lenders under the Facility to increase their commitments (in
each case with the consent of the new lenders or the increasing
lenders). In January 2011, Nabors Delaware added a new lender to
the Facility and increased the total commitments under the
Facility to $750 million. We fully and unconditionally
guarantee the obligations under the Revolving Credit Facility,
which matures in four years.
Borrowings under the Revolving Credit Facility bear interest, at
Nabors Delaware’s option, at either (x) the “Base
Rate” (as defined below) plus the applicable interest
margin, calculated on the basis of the actual number of days
elapsed in a year of 365 days and payable quarterly in
arrears or (y) interest periods of one, two, three or six
months at an annual rate equal to the LIBOR for the
corresponding deposits of U.S. dollars, plus the applicable
interest margin, payable on the last days of the relevant
interest periods (but in any event at least every three months).
The “Base Rate” is defined, for any day, as a
fluctuating rate per annum equal to the highest of (i) the
Federal Funds Rate, as published by the Federal Reserve Bank of
New York, plus
1
/
2
of 1%, (ii) the prime commercial lending rate of UBS AG, as
established from time to time at its Stamford Branch and
(iii) LIBOR for an interest period of one month beginning
on such day plus 1%.
On September 10, 2010, we completed the Superior Merger,
pursuant to which we acquired all of the issued and outstanding
shares of Superior’s common stock, at a price per share
equal to $22.12 for a cash purchase price of approximately
$681.3 million. We paid this amount using cash on hand and
proceeds from the Revolving Credit Facility. Nabors Delaware
repaid the borrowing under the Revolving Credit Facility using
cash on hand and proceeds from the senior notes issued on
September 14, 2010, as discussed below.
On September 14, 2010, Nabors Delaware completed a private
placement of $700 million aggregate principal amount of
5.0% senior notes due 2020, which are unsecured and are
fully and unconditionally guaranteed by us. The senior notes
have registration rights and will mature on September 15,
2020. Nabors Delaware used a portion of the proceeds to repay
the borrowing of $600 million under the Revolving Credit
Facility incurred to fund the acquisition of Superior. We and
Nabors Delaware are using the remaining proceeds for general
corporate purposes.
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On January 20, 2011, in accordance with the registration
rights agreement entered into in connection with the issuance of
the 5.0% senior notes, Nabors Delaware commenced an
exchange offer for the notes pursuant to a registration
statement on
Form S-4,
which was declared effective by the SEC on January 19,
2011. The exchange offer expired on February 23, 2011 and
closed on February 28, 2011.
On December 31, 2010, we purchased the business of Energy
Contractors for a total cash purchase price of
$53.4 million. We paid this amount using cash on hand.
We had five
letter-of-credit
facilities with various banks as of December 31, 2010.
Availability under our
letter-of-credit
facilities as of December 31, 2010 was as follows:
| (In thousands) | ||||
|
Credit available
|
$ | 270,263 | ||
|
Letters of credit outstanding, inclusive of financial and
performance guarantees
|
(70,605 | ) | ||
|
Remaining availability
|
$ | 199,658 | ||
Our ability to access capital markets or to otherwise obtain
sufficient financing is enhanced by our senior unsecured debt
ratings as provided by Fitch Ratings, Moody’s Investors
Service and Standard & Poor’s and our historical
ability to access those markets as needed. While there can be no
assurances that we will be able to access these markets in the
future, we believe that we will be able to access capital
markets or otherwise obtain financing in order to satisfy any
payment obligation that might arise upon exchange or purchase of
our notes and that any cash payment due, in addition to our
other cash obligations, would not ultimately have a material
adverse impact on our liquidity or financial position. A credit
downgrade may impact our ability to access credit markets.
Our current cash and investments, projected cash flows from
operations, possible dispositions of non-core assets and our
Facility are expected to adequately finance our purchase
commitments, our scheduled debt service requirements, and all
other expected cash requirements for the next twelve months.
See our discussion of the impact of changes in market conditions
on our derivative financial instruments under Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Off-Balance
Sheet Arrangements (Including Guarantees)
We are a party to some transactions, agreements or other
contractual arrangements defined as “off-balance sheet
arrangements” that could have a material future effect on
our financial position, results of operations, liquidity and
capital resources. The most significant of these off-balance
sheet arrangements involve agreements and obligations under
which we provide financial or performance assurance to third
parties. Certain of these agreements serve as guarantees,
including standby letters of credit issued on behalf of
insurance carriers in conjunction with our workers’
compensation insurance program and other financial surety
instruments such as bonds. In addition, we have provided
indemnifications, which serve as guarantees, to some third
parties. These guarantees include indemnification provided by
Nabors to our share transfer agent and our insurance carriers.
We are not able to estimate the potential future maximum
payments that might be due under our indemnification guarantees.
Management believes the likelihood that we would be required to
perform or otherwise incur any material losses associated with
any of these guarantees is remote. The following table
summarizes the total maximum amount of financial guarantees
issued by Nabors:
| Maximum Amount | ||||||||||||||||||||
| 2011 | 2012 | 2013 | Thereafter | Total | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Financial standby letters of credit and other financial surety
instruments
|
$ | 83,010 | $ | 525 | $ | 12,158 | $ | — | $ | 95,693 | ||||||||||
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Other
Matters
Risk
Management
In February 2010, our Board of Directors established a Risk
Oversight Committee, which is responsible for
| • | monitoring management’s identification and evaluation of major strategic, operational, regulatory, information and external risks inherent in our business, | |
| • | reviewing the integrity of our systems of operational controls regarding legal and regulatory compliance, and | |
| • | reviewing our processes for managing and mitigating operational risk. |
As discussed in Item 1A. Risk Factors, hazards inhere in
the drilling, well-servicing and workover industries, including
blowouts, cratering, explosions, fires, loss of well control,
loss of or damage to the wellbore or underground reservoir,
damaged or lost drilling equipment and damage or loss from
inclement weather or natural disasters. Any of these hazards
could result in personal injury or death, damage to or
destruction of equipment and facilities, suspension of
operations, environmental damage and damage to the property of
others. Our offshore operations are also subject to the hazards
of marine operations, including capsizing, grounding, collision,
damage from hurricanes and heavy weather or sea conditions and
unsound ocean bottom conditions. Our operations are also subject
to risks arising out of war, civil disturbances or other
political events. We seek to mitigate these risks by
(i) avoiding them to the degree possible through sound
operational and safety practices, (ii) contractual risk
allocation and (iii) insurance.
We employ a top-down focus on safety as one of our main
priorities. From our Chairman and Chief Executive Officer, to
the Board’s Technical & Safety Committee, through
all levels of operations, a shared focus on safety is reflected
in both our historical and ongoing safety performance. Although
we strive to implement sound safety and security practices in
every aspect of our operations, incidents still occur.
Drilling contracts typically apportion the risks of loss between
a drilling contractor and the operator, and we seek to obtain
indemnification from our customers by contract for some of these
risks. Under the standard industry drilling contract, each party
bears responsibility for its own people and property, and other
commonly accepted significant risks are allocated as follows:
| • | risk of damage to the underground reservoir is allocated to the operator; | |
| • | loss of or damage to the hole is allocated to the operator, although the contractor may take responsibility for redrilling the hole at some negotiated discount if the loss is due to the contractor’s negligence or willful misconduct; | |
| • | pollution is allocated to the contractor if it is above the surface of the ground or water and emanates from the contractor’s equipment, with the risk of all other pollution allocated to the operator; | |
| • | the costs associated with bringing a wild well under control are allocated to the operator; and | |
| • | where deemed necessary, some measure of political risk is allocated to the operator. |
Although we strive to achieve this risk structure in our
customer contracts, the actual risk structure may vary
considerably from contract to contract, and there can be no
assurance that we will be able to assign our risk for
catastrophic or other events. Many operators seek to reduce
their exposure for major risks in a number of ways, usually by
shifting the risk to the contractor when its willful misconduct,
gross negligence or even ordinary negligence leads to the damage
at issue. We resist the imposition of such liabilities and
attempt to negotiate monetary caps when we are unable to assign
these risks altogether. Nevertheless, we sometimes accept
liability for major risks when we determine from an overall
risk-reward analysis, considering both risk inherent in the
particular work and available insurance coverage, that such
risks are within our risk tolerance.
Finally, to the extent that we are unable to transfer risks to
our customers through contractual indemnities or our customers
fail to honor their contractual responsibilities, we seek to
limit our exposure through
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insurance. We maintain coverage for personal injury and property
damage, business interruption, political and war risk,
contractual liabilities, sudden and accidental pollution,
well-control costs and other potential liabilities. We believe
that we carry sufficient insurance coverage and limits to
protect us against our exposure to major risks. However, there
is no assurance that such insurance will adequately protect us
against liability from all of the consequences of the hazards
described above. Moreover, our insurance coverage generally
provides that we assume a portion of the risk in the form of a
deductible or self-insured retention.
Recent
Legislation and Actions
In February 2009, Congress enacted the American Recovery and
Reinvestment Act of 2009 (the “Stimulus Act”). The
Stimulus Act is intended to provide a stimulus to the
U.S. economy, including relief to companies related to
income on debt repurchases and exchanges at a discount,
expansion of unemployment benefits to former employees and other
social welfare provisions. The Stimulus Act has not had a
significant impact on our consolidated financial statements.
In March 2010, the EPA announced that it would study the
potential adverse impact that hydraulic fracturing may have on
water quality and public health. On September 14, 2010, the
EPA sent letters to nine companies that perform fracturing
services in the United States, including Superior. The letter
requests information regarding the chemical composition of
fluids used, information about the impacts of the chemicals on
human health and the environment, standard operating procedures
at fracturing sites and a list of sites where the companies have
carried out the process. The EPA has indicated that it plans to
perform more detailed analyses based on the information received
and would seek to compel submission of the information if
necessary. Nabors is and intends to continue providing requested
information and cooperating with the EPA’s investigation.
Legislation has also been introduced in the U.S. Congress
and some states that would require the disclosure of chemicals
used in the fracturing process. If enacted, the legislation
could require fracturing activities to meet permitting and
financial assurance requirements, adhere to certain construction
specifications, fulfill monitoring, reporting and recordkeeping
requirements and meet plugging and abandonment requirements. Any
new laws regulating fracturing activities could cause
operational delays or increased costs in exploration and
production, which could adversely affect the demand for
fracturing services. We cannot currently predict what the
findings of the investigation will be, what regulatory changes
might be implemented, or what the ultimate impact may be on the
results of our Pressure Pumping operating segment.
Recent
Accounting Pronouncements
In December 2008, the SEC issued a Final Rule,
“Modernization of Oil and Gas Reporting.” This rule
revises some of the oil and gas reporting disclosures in
Regulation S-K
and
Regulation S-X
under the Securities Act and the Exchange Act, as well as
Industry Guide 2. Effective December 31, 2009, the FASB
issued revised guidance that substantially aligned the oil and
gas accounting disclosures with the SEC’s Final Rule. The
amendments are designed to modernize and update oil and gas
disclosure requirements to align them with current practices and
changes in technology. Additionally, this new accounting
standard requires that entities use
12-month
average natural gas and oil prices when calculating the
quantities of proved reserves and performing the full-cost
ceiling test calculation. The new standard also clarified that
an entity’s equity-method investments must be considered in
determining whether it has significant oil and gas activities.
The disclosure requirements are effective for registration
statements filed on or after January 1, 2010 and for annual
financial statements filed on or after January 1, 2010. The
FASB provided a one-year deferral of the disclosure requirements
if an entity became subject to the requirements because of a
change to the definition of significant oil and gas activities.
When operating results from our wholly owned oil and gas
activities are considered with operating results from our
unconsolidated oil and gas joint ventures, which we account for
under the equity method of accounting, we have significant oil
and gas activities under the new definition. Our oil and gas
disclosures are provided in Note 24 —
Supplemental Information on Oil and Gas Exploration and
Production Activities in Part II Item 8. —
Financial Statements and Supplementary Data.
Effective January 1, 2010, we adopted the revised
provisions relating to consolidation of variable interest
entities within the Consolidations Topic of the ASC. The revised
provisions replaced the quantitative approach to identify a
variable interest entity with a qualitative approach that
focuses on an entity’s control and ability
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Table of Contents
to direct the variable interest entity’s activities. The
application of these provisions did not have a material impact
on our consolidated financial statements.
The FASB issued new guidance relating to revenue recognition for
contractual arrangements with multiple revenue-generating
activities. The ASC Topic for revenue recognition includes
identification of a unit of accounting and how arrangement
consideration should be allocated to separate the units of
accounting, when applicable. The new guidance, including
expanded disclosures, will apply to us for contracts entered
into after June 15, 2010. We are evaluating the impact this
guidance may have on future contracts. Historically, we have not
entered into contractual agreements with multiple
revenue-generating activities.
Related-Party
Transactions
Nabors and its Chairman and Chief Executive Officer, its Deputy
Chairman, President and Chief Operating Officer, and certain
other key employees entered into split-dollar life insurance
agreements, pursuant to which we paid a portion of the premiums
under life insurance policies with respect to these individuals
and, in some instances, members of their families. These
agreements provide that we are reimbursed the premium payments
upon the occurrence of specified events, including the death of
an insured individual. Any recovery of premiums paid by Nabors
could be limited to the cash surrender value of the policies
under certain circumstances. As such, the values of these
policies are recorded at their respective cash surrender values
in our consolidated balance sheets. We have made premium
payments to date totaling $11.7 million related to these
policies. The cash surrender value of these policies of
approximately $9.5 million and $9.3 million is
included in other long-term assets in our consolidated balance
sheets as of December 31, 2010 and 2009, respectively.
Under the Sarbanes-Oxley Act of 2002, the payment of premiums by
Nabors under the agreements with our Chairman and Chief
Executive Officer and with our Deputy Chairman, President and
Chief Operating Officer could be deemed to be prohibited loans
by us to these individuals. Consequently, we have paid no
premiums related to our agreements with these individuals since
the adoption of the Sarbanes-Oxley Act.
In the ordinary course of business, we enter into various rig
leases, rig transportation and related oilfield services
agreements with our unconsolidated affiliates at market prices.
Revenues from business transactions with these affiliated
entities totaled $271.6 million, $327.3 million and
$285.3 million for the years ended December 31, 2010,
2009 and 2008, respectively. Expenses from business transactions
with these affiliated entities totaled $3.4 million,
$9.8 million and $9.6 million for the years ended
December 31, 2010, 2009 and 2008, respectively.
Additionally, we had accounts receivable from these affiliated
entities of $97.8 million and $104.2 million as of
December 31, 2010 and 2009, respectively. We had accounts
payable to these affiliated entities of $12.7 million and
$14.8 million as of December 31, 2010 and 2009,
respectively, and long-term payables with these affiliated
entities of $.8 million as of each of December 31,
2010 and 2009, respectively, which is included in other
long-term liabilities.
In addition to the equity investment in our unconsolidated
U.S. oil and gas joint venture, in April 2010 we purchased
$20.0 million face value of NFR Energy LLC’s
9.75% senior notes. These notes mature in 2017 with
interest payable semi-annually on February 15 and
August 15. During 2010, we recognized $1.4 million in
interest income from these notes.
We own an interest in Shona Energy Company, LLC
(“Shona”), a company of which Mr. Payne, an
independent member of our Board of Directors, is the Chairman
and Chief Executive Officer. During the fourth quarter of 2008,
we purchased 1.8 million common shares of Shona for
$.9 million. During the first quarter of 2010, we purchased
shares of Shona’s preferred stock and warrants to purchase
additional common shares for $.9 million. We currently hold
a minority interest of approximately 10% of the issued and
outstanding shares of Shona.
Critical
Accounting Estimates
The preparation of our financial statements in conformity with
GAAP requires management to make certain estimates and
assumptions. These estimates and assumptions affect the reported
amounts of assets and
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liabilities, the disclosures of contingent assets and
liabilities at the balance sheet date and the amounts of
revenues and expenses recognized during the reporting period. We
analyze our estimates based on our historical experience and
various other assumptions that we believe to be reasonable under
the circumstances. However, actual results could differ from our
estimates. The following is a discussion of our critical
accounting estimates. Management considers an accounting
estimate to be critical if:
| • | it requires assumptions to be made that were uncertain at the time the estimate was made; and | |
| • | changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated financial position or results of operations. |
For a summary of all of our significant accounting policies, see
Note 2 — Summary of Significant Accounting
Policies in Part II, Item 8. — Financial
Statements and Supplementary Data.
Financial Instruments.
As defined in the ASC,
fair value is the price that would be received upon a sale of an
asset or paid upon a transfer of a liability in an orderly
transaction between market participants at the measurement date
(exit price). We utilize market data or assumptions that market
participants would use in pricing the asset or liability,
including assumptions about risk and the risks inherent in the
inputs to the valuation technique. These inputs can be readily
observable, market-corroborated, or generally unobservable. We
primarily apply the market approach for recurring fair value
measurements and endeavor to utilize the best information
available. Accordingly, we employ valuation techniques that
maximize the use of observable inputs and minimize the use of
unobservable inputs. The use of unobservable inputs is intended
to allow for fair value determinations in situations where there
is little, if any, market activity for the asset or liability at
the measurement date. We are able to classify fair value
balances utilizing a fair-value hierarchy based on the
observability of those inputs. Under the fair-value hierarchy
| • | Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market; | |
| • | Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and | |
| • | Level 3 measurements include those that are unobservable and of a highly subjective measure. |
Depreciation of Property, Plant and
Equipment.
The drilling, workover and
well-servicing and pressure pumping industries are very capital
intensive. Property, plant and equipment represented 67% of our
total assets as of December 31, 2010, and depreciation
constituted 19% of our total costs and other deductions for the
year ended December 31, 2010.
Depreciation for our primary operating assets, drilling and
workover rigs, is calculated based on the
units-of-production
method. For each day a rig is operating, we depreciate it over
an approximate 4,900-day period, with the exception of our
jack-up
rigs
which are depreciated over an 8,030-day period, after provision
for salvage value. For each day a rig asset is not operating, it
is depreciated over an assumed depreciable life of
20 years, with the exception of our
jack-up
rigs, where a
30-year
depreciable life is typically used, after provision for salvage
value.
Depreciation on our buildings, well-servicing rigs, oilfield
hauling and mobile equipment, marine transportation and supply
vessels, aircraft equipment, and other machinery and equipment
is computed using the straight-line method over the estimated
useful life of the asset after provision for salvage value
(buildings — 10 to 30 years; well-servicing
rigs — 3 to 15 years; marine transportation and
supply vessels — 10 to 25 years; aircraft
equipment — 5 to 20 years; oilfield hauling and
mobile equipment and other machinery and equipment — 3
to 10 years).
These depreciation periods and the salvage values of our
property, plant and equipment were determined through an
analysis of the useful lives of our assets and based on our
experience with the salvage values of these assets.
Periodically, we review our depreciation periods and salvage
values for reasonableness given
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current conditions. Depreciation of property, plant and
equipment is therefore based upon estimates of the useful lives
and salvage value of those assets. Estimation of these items
requires significant management judgment. Accordingly,
management believes that accounting estimates related to
depreciation expense recorded on property, plant and equipment
are critical.
There have been no factors related to the performance of our
portfolio of assets, changes in technology or other factors that
indicate that these estimates do not continue to be appropriate.
Accordingly, for the years ended December 31, 2010, 2009
and 2008, no significant changes have been made to the
depreciation rates applied to property, plant and equipment, the
underlying assumptions related to estimates of depreciation, or
the methodology applied. However, certain events could occur
that would materially affect our estimates and assumptions
related to depreciation. Unforeseen changes in operations or
technology could substantially alter management’s
assumptions regarding our ability to realize the return on our
investment in operating assets and therefore affect the useful
lives and salvage values of our assets.
Impairment of Long-Lived Assets.
As discussed
above, the drilling, workover and well-servicing and pressure
pumping industry is very capital intensive. We review our assets
for impairment when events or changes in circumstances indicate
that the carrying amounts of property, plant and equipment may
not be recoverable. An impairment loss is recorded in the period
in which it is determined that the sum of estimated future cash
flows, on an undiscounted basis, is less than the carrying
amount of the long-lived asset. Such determination requires us
to make judgments regarding long-term forecasts of future
revenues and costs related to the assets subject to review in
order to determine the future cash flows associated with the
assets. These long-term forecasts are uncertain because they
require assumptions about demand for our products and services,
future market conditions, technological advances in the industry
and changes in regulations governing the industry. Significant
and unanticipated changes to the assumptions could result in
future impairments. As the determination of whether impairment
charges should be recorded on our long-lived assets is subject
to significant management judgment and an impairment of these
assets could result in a material charge on our consolidated
statements of income (loss), management believes that accounting
estimates related to impairment of long-lived assets are
critical.
Assumptions made in the determination of future cash flows are
made with the involvement of management personnel at the
operational level where the most specific knowledge of market
conditions and other operating factors exists. For the years
ended December 31, 2010, 2009 and 2008, no significant
changes have been made to the methodology utilized to determine
future cash flows.
Given the nature of the evaluation of future cash flows and the
application to specific assets and specific times, it is not
possible to reasonably quantify the impact of changes in these
assumptions. A significantly prolonged period of lower oil and
natural gas prices could continue to adversely affect the demand
for and prices of our services, which could result in future
impairment charges.
Impairment of Goodwill and Intangible
Assets.
Goodwill represented 4.2% of our total
assets as of December 31, 2010. We review goodwill and
intangible assets with indefinite lives for impairment annually
or more frequently if events or changes in circumstances
indicate that the carrying amount of such goodwill and
intangible assets exceed their fair value. During the second
quarter of 2010, we performed our impairment tests of goodwill
and intangible assets for all of our reporting units within our
operating segments. These reporting units consist of our
contract drilling segments: U.S. Lower 48 Land Drilling,
U.S. Land Well-servicing, U.S. Offshore, Alaska,
Canada and International; our oil and gas segment; and our other
operating segments: Canrig Drilling Technology Ltd., Ryan Energy
Technologies and Nabors Blue Sky Ltd. The impairment test
involves comparing the estimated fair value of the reporting
unit to its carrying amount. If the carrying amount of the
reporting unit exceeds its fair value, a second step is required
to measure the goodwill impairment loss. This second step
compares the implied fair value of the reporting unit’s
goodwill to the carrying amount of that goodwill. If the
carrying amount of the reporting unit’s goodwill exceeds
the implied fair value of the goodwill, an impairment loss is
recognized in an amount equal to the excess. Our impairment test
results required the second step measurement for one reporting
unit during each of 2010 and 2009.
The fair values calculated in these impairment tests are
determined using discounted cash flow models involving
assumptions based on our utilization of rigs or aircraft,
revenues and earnings from affiliates, as well
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as direct costs, general and administrative costs, depreciation,
applicable income taxes, capital expenditures and working
capital requirements. Our discounted cash flow projections for
each reporting unit were based on financial forecasts. The
future cash flows were discounted to present value using
discount rates that are determined to be appropriate for each
reporting unit. Terminal values for each reporting unit were
calculated using a Gordon Growth methodology with a long-term
growth rate of 3%. We believe the fair value estimated for
purposes of these tests represent a Level 3 fair value
measurement.
During 2010, 2009 and 2008, we recognized goodwill impairments
of approximately $10.7 million, $14.7 million and
$150.0 million, respectively. During 2008, we impaired the
entire goodwill balance of $145.4 million of our Canada
Well-servicing and Drilling operating segment and recorded an
impairment of $4.6 million to Nabors Blue Sky Ltd., one of
our Canadian subsidiaries reported in our Other Operating
segments. During 2009, we impaired the remaining goodwill
balance of $14.7 million of Nabors Blue Sky Ltd. The
impairment charges were deemed necessary due to the continued
downturn in the oil and gas industry in Canada and the lack of
certainty regarding eventual recovery in the value of these
operations. This downturn has led to reduced capital spending by
our customers and diminished demand for our drilling services
and for immediate access to remote drilling sites. The
impairment charge during 2010 was recorded in our
U.S. Offshore operating segment and was deemed necessary
due to the uncertainty of utilization of some of our rigs as a
result of changes in our customers’ plans for future
drilling operations in the Gulf of Mexico. Many of our customers
have suspended drilling operations in the Gulf of Mexico,
largely as a result of their inability to obtain government
permits. A significantly prolonged period of lower oil and
natural gas prices or changes in laws and regulations could
continue to adversely affect the demand for and prices of our
services, which could result in future goodwill impairment
charges for other reporting units due to the potential impact on
our estimate of our future operating results.
Oil and Gas Properties.
We follow the
successful-efforts method of accounting for our consolidated
subsidiaries’ oil and gas activities. Under the
successful-efforts method, lease acquisition costs and all
development costs are capitalized. Our provision for depletion
is based on these capitalized costs and is determined on a
property-by-property
basis using the
units-of-production
method. Proved property acquisition costs are amortized over
total proved reserves. Costs of wells and related equipment and
facilities are amortized over the life of proved developed
reserves. Estimated fair value of proved and unproved properties
includes the estimated present value of all reasonably expected
future production, prices and costs. Proved oil and gas
properties are reviewed when circumstances suggest the need for
such a review and, are written down to their estimated fair
value, if required. Unproved properties are reviewed to
determine if there has been impairment of the carrying value and
when circumstances suggest an impairment has occurred, are
written down to their estimated fair value in that period. The
estimated fair value of our proved reserves generally declines
when there is a significant and sustained decline in oil and
natural gas prices. During 2010, 2009 and 2008, our impairment
tests on our wholly owned oil and gas assets of our Oil and Gas
operating segment resulted in impairment charges of
$137.8 million, $48.6 million and $21.5 million,
respectively. As discussed above in
Recent Accounting
Pronouncements,
we adopted new guidance relating to the
manner in which our oil and gas reserves are estimated as of
December 31, 2009.
Exploratory drilling costs are capitalized until the results are
determined. If proved reserves are not discovered, the
exploratory drilling costs are expensed. Interest costs related
to financing major oil and gas projects in progress are
capitalized until the projects are evaluated or until the
projects are substantially complete and ready for their intended
use if the projects are evaluated as successful. Other
exploratory costs are expensed as incurred.
Our unconsolidated oil and gas joint ventures, which we account
for under the equity method of accounting, utilize the full-cost
method of accounting for costs related to oil and natural gas
properties. Under this method, all such costs (for both
productive and nonproductive properties) are capitalized and
amortized on an aggregate basis over the estimated lives of the
properties using the
units-of-production
method. However, these capitalized costs are subject to a
ceiling test which limits such pooled costs to the aggregate of
the present value of future net revenues attributable to proved
oil and natural gas reserves, discounted at 10%, plus the lower
of cost or market value of unproved properties. As discussed
above in
Recent Accounting Pronouncements
and in relation
to the full-cost ceiling test, our unconsolidated oil and gas
joint ventures
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changed the manner in which their oil and gas reserves are
estimated and the manner in which they calculate the ceiling
limit on capitalized oil and gas costs as of December 31,
2009. Under the new guidance, future revenues for purposes of
the ceiling test are valued using a
12-month
average price, adjusted for the impact of derivatives accounted
for as cash flow hedges as prescribed by the SEC rules. No
full-cost ceiling test writedowns were recorded by our
unconsolidated oil and gas joint ventures during 2010. During
2009, our proportionate share of those ventures’ full-cost
ceiling test writedowns was $237.1 million.
During 2008, our unconsolidated oil and gas joint ventures
evaluated the full-cost ceiling using then-current prices for
oil and natural gas, adjusted for the impact of derivatives
accounted for as cash flow hedges. As a result, our
proportionate share of those ventures’ full-cost ceiling
test writedowns was $228.3 million.
A significantly prolonged period of lower oil and natural gas
prices or reserve quantities could continue to adversely affect
the demand for and prices of our services, which could result in
future impairment charges due to the potential impact on our
estimate of our future operating results.
Oil and Gas Reserves.
Evaluations of oil and
gas reserves are integral to making investment decisions about
oil and gas properties such as whether development should
proceed. Oil and gas reserve quantities are also used as the
basis for calculating
unit-of-production
depreciation rates and for evaluating impairment. Oil and gas
reserves include both proved and unproved reserves. Consistent
with the definitions provided by the SEC, proved oil and gas
reserves are those quantities of oil and gas, which, by analysis
of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible from a given
date forward, known reservoirs, and under existing economic
conditions. Unproved reserves are those with less than
reasonable certainty of recoverability and include probable
reserves. Probable reserves are reserves that are more likely to
be recovered than not.
Estimation of proved reserves, which is based on the requirement
of reasonable certainty, is an ongoing process involving
rigorous technical evaluations, commercial and market
assessment, and detailed analysis of well information such as
flow rates and reservoir pressure declines. Although we are
reasonably certain that proved reserves will be produced, the
timing and amount recovered can be affected by a number of
factors including completion of development projects, reservoir
performance, regulatory approvals and significant changes in
long-term oil and gas price levels.
Income Taxes.
Deferred taxes represent a
substantial liability for Nabors. For financial reporting
purposes, management determines our current tax liability as
well as those taxes incurred as a result of current operations
yet deferred until future periods. In accordance with the
liability method of accounting for income taxes as specified in
the Income Taxes Topic of the ASC, the provision for income
taxes is the sum of income taxes both currently payable and
deferred. Currently payable taxes represent the liability
related to our income tax return for the current year while the
net deferred tax expense or benefit represents the change in the
balance of deferred tax assets or liabilities reported on our
consolidated balance sheets. The tax effects of unrealized gains
and losses on investments and derivative financial instruments
are recorded through accumulated other comprehensive income
(loss) within equity. The changes in deferred tax assets or
liabilities are determined based upon changes in differences
between the basis of assets and liabilities for financial
reporting purposes and the basis of assets and liabilities for
tax purposes as measured by the enacted tax rates that
management estimates will be in effect when these differences
reverse. Management must make certain assumptions regarding
whether tax differences are permanent or temporary and must
estimate the timing of their reversal, and whether taxable
operating income in future periods will be sufficient to fully
recognize any gross deferred tax assets. Valuation allowances
are established to reduce deferred tax assets when it is more
likely than not that some portion or all of the deferred tax
assets will not be realized. In determining the need for
valuation allowances, management has considered and made
judgments and estimates regarding estimated future taxable
income and ongoing prudent and feasible tax planning strategies.
These judgments and estimates are made for each tax jurisdiction
in which we operate as the calculation of deferred taxes is
completed at that level. Further, under U.S. federal tax
law, the amount and availability of loss carryforwards (and
certain other tax attributes) are subject to a variety of
interpretations and restrictive tests applicable to Nabors and
our subsidiaries. The utilization of such carryforwards could be
limited or effectively lost upon certain changes in ownership.
Accordingly, although we believe substantial loss carryforwards
are available to us, no assurance
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can be given concerning the realization of such loss
carryforwards, or whether or not such loss carryforwards will be
available in the future. These loss carryforwards are also
considered in our calculation of taxes for each jurisdiction in
which we operate. Additionally, we record reserves for uncertain
tax positions that are subject to a significant level of
management judgment related to the ultimate resolution of those
tax positions. Accordingly, management believes that the
estimate related to the provision for income taxes is critical
to our results of operations. See Part I,
Item 1A. — Risk Factors —
We may
have additional tax liabilities
and Note 12 —
Income Taxes in Part II, Item 8. — Financial
Statements and Supplementary Data for additional discussion.
We are subject to income taxes in both the United States and
numerous other jurisdictions. Significant judgment is required
in determining our worldwide provision for income taxes. In the
ordinary course of our business, there are many transactions and
calculations where the ultimate tax determination is uncertain.
We are regularly audited by tax authorities. Although we believe
our tax estimates are reasonable, the final determination of tax
audits and any related litigation could be materially different
than that reflected in historical income tax provisions and
accruals. An audit or litigation could materially affect our
financial position, income tax provision, net income, or cash
flows in the period or periods challenged. However, certain
events could occur that would materially affect
management’s estimates and assumptions regarding the
deferred portion of our income tax provision, including
estimates of future tax rates applicable to the reversal of tax
differences, the classification of timing differences as
temporary or permanent, reserves recorded for uncertain tax
positions and any valuation allowance recorded as a reduction to
our deferred tax assets. Management’s assumptions related
to the preparation of our income tax provision have historically
proved to be reasonable in light of the ultimate amount of tax
liability due in all taxing jurisdictions.
For the year ended December 31, 2010, our provision for
income taxes from continuing operations was
$(24.8) million, consisting of $(83.8) million of
current tax benefit and $59.0 million of deferred tax
expense. Changes in management’s estimates and assumptions
regarding the tax rate applied to deferred tax assets and
liabilities, the ability to realize the value of deferred tax
assets, or the timing of the reversal of tax basis differences
could potentially impact the provision for income taxes and
could potentially change the effective tax rate. A 1% change in
the effective tax rate from (30.2%) to (29.2%) would increase
the current year income tax provision by approximately
$.8 million.
Self-Insurance Reserves.
Our operations are
subject to many hazards inherent in the drilling, workover and
well-servicing and pressure pumping industries, including
blowouts, cratering, explosions, fires, loss of well control,
loss of or damage to the wellbore or underground reservoir,
damaged or lost drilling equipment and damage or loss from
inclement weather or natural disasters. Any of these hazards
could result in personal injury or death, damage to or
destruction of equipment and facilities, suspension of
operations, environmental and natural resources damage and
damage to the property of others. Our offshore operations are
also subject to the hazards of marine operations including
capsizing, grounding, collision and other damage from hurricanes
and heavy weather or sea conditions and unsound ocean bottom
conditions. Our operations are subject to risks of war, civil
disturbances or other political events.
Accidents may occur, we may be unable to obtain desired
contractual indemnities, and our insurance may prove inadequate
in certain cases. There is no assurance that such insurance or
indemnification agreements will adequately protect us against
liability from all of the consequences of the hazards described
above. Moreover, our insurance coverage generally provides that
we assume a portion of the risk in the form of a deductible or
self-insured retention.
Based on the risks discussed above, it is necessary for us to
estimate the level of our liability related to insurance and
record reserves for these amounts in our consolidated financial
statements. Reserves related to self-insurance are based on the
facts and circumstances specific to the claims and our past
experience with similar claims. The actual outcome of
self-insured claims could differ significantly from estimated
amounts. We maintain actuarially determined accruals in our
consolidated balance sheets to cover self-insurance retentions
for workers’ compensation, employers’ liability,
general liability and automobile liability claims. These
accruals are based on certain assumptions developed utilizing
historical data to project future losses. Loss estimates in the
calculation of these accruals are adjusted based upon actual
claim settlements and
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reported claims. These loss estimates and accruals recorded in
our financial statements for claims have historically been
reasonable in light of the actual amount of claims paid.
Because the determination of our liability for self-insured
claims is subject to significant management judgment and in
certain instances is based on actuarially estimated and
calculated amounts, and because such liabilities could be
material in nature, management believes that accounting
estimates related to self-insurance reserves are critical.
During 2010, 2009 and 2008, no significant changes were made to
the methodology utilized to estimate insurance reserves. For
purposes of earnings sensitivity analysis, if the
December 31, 2010 reserves for insurance were adjusted
(increased or decreased) by 10%, total costs and other
deductions would change by $14.6 million, or .4%.
Fair Value of Assets Acquired and Liabilities
Assumed.
We have completed a number of
acquisitions in recent years as discussed in
Note 5 — Fair Value Measurements in Part II,
Item 8. — Financial Statements and Supplementary
Data. In conjunction with our accounting for these acquisitions,
it was necessary for us to estimate the values of the assets
acquired and liabilities assumed in the various business
combinations using various assumptions. These estimates may be
affected by such factors as changing market conditions,
technological advances in the industry or changes in regulations
governing the industry. The most significant assumptions, and
the ones requiring the most judgment, involve the estimated fair
values of property, plant and equipment, and the resulting
amount of goodwill, if any. Unforeseen changes in operations or
technology could substantially alter management’s
assumptions and could result in lower estimates of values of
acquired assets or of future cash flows. This could result in
impairment charges being recorded in our consolidated statements
of income (loss). As the determination of the fair value of
assets acquired and liabilities assumed is subject to
significant management judgment and a change in purchase price
allocations could result in a material difference in amounts
recorded in our consolidated financial statements, management
believes that accounting estimates related to the valuation of
assets acquired and liabilities assumed are critical.
The determination of the fair value of assets and liabilities is
based on the market for the assets and the settlement value of
the liabilities. These estimates are made by management based on
our experience with similar assets and liabilities. During 2010,
2009 and 2008, no significant changes were made to the
methodology utilized to value assets acquired or liabilities
assumed. Our estimates of the fair values of assets acquired and
liabilities assumed have proved to be reliable in the past.
Given the nature of the evaluation of the fair value of assets
acquired and liabilities assumed and the application to specific
assets and liabilities, it is not possible to reasonably
quantify the impact of changes in these assumptions.
Share-Based Compensation.
We have historically
compensated our executives and employees, in part, with stock
options and restricted stock. Based on the requirements of the
Stock Compensation Topic of the ASC, we accounted for stock
option and restricted stock awards in 2008, 2009 and 2010 using
a fair-value based method, resulting in compensation expense for
stock-based awards being recorded in our consolidated statements
of income (loss). Determining the fair value of stock-based
awards at the grant date requires judgment, including estimating
the expected term of stock options, the expected volatility of
our stock and expected dividends. In addition, judgment is
required in estimating the amount of stock-based awards that are
expected to be forfeited. Because the determination of these
various assumptions is subject to significant management
judgment and different assumptions could result in material
differences in amounts recorded in our consolidated financial
statements, management believes that accounting estimates
related to the valuation of stock-based awards are critical.
The assumptions used to estimate the fair market value of our
stock options are based on historical and expected performance
of our common shares in the open market, expectations with
regard to the pattern with which our employees will exercise
their options and the likelihood that dividends will be paid to
holders of our common shares. During 2010, 2009 and 2008, no
significant changes were made to the methodology utilized to
determine the assumptions used in these calculations.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
We may be exposed to certain market risks arising from the use
of financial instruments in the ordinary course of business.
This risk arises primarily as a result of potential changes in
the fair market value of financial instruments due to adverse
fluctuations in foreign currency exchange rates, credit risk,
interest rates, and marketable and non-marketable security
prices as discussed below.
Foreign Currency Risk.
We operate in a number
of international areas and are involved in transactions
denominated in currencies other than U.S. dollars, which
exposes us to foreign exchange rate risk and foreign currency
devaluation risk. The most significant exposures arise in
connection with our operations in Venezuela and Canada, which
usually are substantially unhedged.
At various times, we utilize local currency borrowings (foreign
currency-denominated debt), the payment structure of customer
contracts and foreign exchange contracts to selectively hedge
our exposure to exchange rate fluctuations in connection with
monetary assets, liabilities, cash flows and commitments
denominated in certain foreign currencies. A foreign exchange
contract is a foreign currency transaction, defined as an
agreement to exchange different currencies at a given future
date and at a specified rate. A hypothetical 10% decrease in the
value of all our foreign currencies relative to the
U.S. dollar as of December 31, 2010 would result in a
$12.2 million decrease in the fair value of our net
monetary assets denominated in currencies other than
U.S. dollars.
Credit Risk.
Our financial instruments that
potentially subject us to concentrations of credit risk consist
primarily of cash equivalents, short-term and long-term
investments, oil and gas financing receivables, accounts
receivable and our range-cap-and-floor derivative instrument.
Cash equivalents such as deposits and temporary cash investments
are held by major banks or investment firms. Our short-term and
long-term investments are managed within established guidelines
which limit the amounts that may be invested with any one issuer
and provide guidance as to issuer credit quality. We believe
that the credit risk in our cash and investment portfolio is
minimized as a result of the mix of our investments. In
addition, our trade receivables are with a variety of U.S.,
international and foreign-country national oil and gas
companies. Management considers this credit risk to be limited
due to the financial resources of these companies. We perform
ongoing credit evaluations of our customers and we generally do
not require material collateral. We do occasionally require
prepayment of amounts from customers whose creditworthiness is
in question prior to providing services to them. We maintain
reserves for potential credit losses, and these losses
historically have been within management’s expectations.
Interest Rate, and Marketable and Non-marketable Security
Price Risk.
Our financial instruments that are
potentially sensitive to changes in interest rates include the
0.94% senior exchangeable notes, our 5.375%, 6.15%, 9.25%
and 5.0% senior notes, our range-cap-and-floor derivative
instrument, our investments in debt securities (including
corporate, asset-backed, mortgage-backed debt and mortgage-CMO
debt securities) and our investments in overseas funds that
invest primarily in a variety of public and private
U.S. and
non-U.S. securities
(including asset-backed and mortgage-backed securities, global
structured-asset securitizations, whole-loan mortgages, and
participations in whole loans and whole-loan mortgages), which
are classified as long-term investments.
We may utilize derivative financial instruments that are
intended to manage our exposure to interest rate risks. We
account for derivative financial instruments under the
Derivatives Topic of the ASC. The use of derivative financial
instruments could expose us to further credit risk and market
risk. Credit risk in this context is the failure of a
counterparty to perform under the terms of the derivative
contract. When the fair value of a derivative contract is
positive, the counterparty would owe us, which can create credit
risk for us. When the fair value of a derivative contract is
negative, we would owe the counterparty, and therefore, we would
not be exposed to credit risk. We attempt to minimize credit
risk in derivative instruments by entering into transactions
with major financial institutions that have a significant asset
base. Market risk related to derivatives is the adverse effect
on the value of a financial instrument that results from changes
in interest rates. We try to manage market risk associated with
interest-rate contracts by establishing and monitoring
parameters that limit the type and degree of market risk that we
undertake.
On October 21, 2002, we entered into an interest rate swap
transaction with a third-party financial institution to hedge
our exposure to changes in the fair value of $200 million
of our fixed rate 5.375% senior
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notes due 2012, which has been designated as a fair value hedge.
Additionally on that date, we purchased a LIBOR range-cap and
sold a LIBOR floor, in the form of a cashless collar, with the
same third-party financial institution with the intention of
mitigating and managing our exposure to changes in the
three-month U.S. dollar LIBOR rate. This transaction does
not qualify for hedge accounting treatment and any change in the
cumulative fair value of this transaction is reflected as a gain
or loss in our consolidated statements of income (loss). In June
2004, we unwound $100 million of the $200 million
range-cap-and-floor derivative instrument. During the fourth
quarter of 2005, we unwound the interest rate swap resulting in
a loss of $2.7 million, which has been deferred and will be
recognized as an increase to interest expense over the remaining
life of our 5.375% senior notes due 2012. During the year
ended December 31, 2005, we recorded interest savings of
$2.7 million related to our interest rate swap agreement
accounted for as a fair value hedge, which served to reduce
interest expense.
The fair value of our range-cap-and-floor transaction is
recorded as a derivative liability and included in other
long-term liabilities. It totaled approximately
$3.4 million and $3.3 million as of December 31,
2010 and 2009, respectively. During 2010, 2009 and 2008, we
recorded gains (losses) of approximately $(.1) million,
$1.4 million and $(4.7) million, respectively, related
to this derivative instrument; these amounts are included in
losses (gains) on sales and retirements of long-lived assets and
other expense (income), net in our consolidated statements of
income (loss).
A hypothetical 10% adverse shift in quoted interest rates as of
December 31, 2010 would decrease the fair value of our
range-cap-and-floor derivative instrument by approximately
$.1 million.
In September 2008 we entered into a three-month written put
option for one million of our common shares with a strike price
of $25 per share. We settled this contract during the fourth
quarter of 2008 and paid cash of $22.6 million, net of the
premium received, and recognized a loss of $9.9 million
which is included in losses (gains) on sales and retirements of
long-lived assets and other expense (income), net in our
consolidated statements of income (loss).
Fair Value of Financial Instruments.
We
estimate the fair value of our financial instruments in
accordance with the provisions of the Fair Value Measurements
and Disclosures Topic of the ASC. The fair value of our fixed
rate long-term debt is estimated based on quoted market prices
or prices quoted from third-party financial institutions. The
fair value of the subsidiary preferred stock was estimated based
on the allocation of the purchase price. See
Note 7 — Acquisitions and Divestitures in
Part II, Item 8. — Financial Statements and
Supplementary Data for additional discussion. The carrying and
fair values of these liabilities were as follows:
| December 31, | ||||||||||||||||||||||||
| 2010 | 2009 | |||||||||||||||||||||||
|
Effective
|
Effective
|
|||||||||||||||||||||||
|
Interest
|
Carrying
|
Fair
|
Interest
|
Carrying
|
Fair
|
|||||||||||||||||||
| Rate | Value | Value | Rate | Value | Value | |||||||||||||||||||
| (In thousands, except interest rates) | ||||||||||||||||||||||||
|
0.94% senior exchangeable notes due May 2011(1)
|
6.13 | % | $ | 1,378,178 | $ | 1,403,315 | 6.13 | % | $ | 1,576,480 | $ | 1,668,368 | ||||||||||||
|
6.15% senior notes due February 2018
|
6.42 | % | 966,276 | 1,041,008 | 6.42 | % | 965,066 | 992,531 | ||||||||||||||||
|
9.25% senior notes due January 2019
|
9.33 | % | 1,125,000 | 1,393,943 | 9.40 | % | 1,125,000 | 1,403,719 | ||||||||||||||||
|
5.00% senior notes due September 2020
|
5.20 | % | 697,037 | 678,335 | — | — | — | |||||||||||||||||
|
5.375% senior notes due August 2012(2)
|
5.61 | % | 273,977 | 291,500 | 5.69 | % | 273,350 | 289,072 | ||||||||||||||||
|
Subsidiary preferred stock
|
4.0 | % | 69,188 | 68,625 | — | — | — | |||||||||||||||||
|
Other
|
2,676 | 2,676 | 4.50 | % | 872 | 872 | ||||||||||||||||||
| $ | 4,512,332 | $ | 4,879,402 | $ | 3,940,768 | $ | 4,354,562 | |||||||||||||||||
60
Table of Contents
| (1) | During 2010 and 2009, we purchased $281.8 million and $964.8 million, respectively, par value of these notes in the open market. | |
| (2) | Includes $.7 million and $1.1 million as of December 31, 2010 and 2009, respectively, related to the unamortized loss on the interest rate swap that was unwound during the fourth quarter of 2005. |
The fair values of our cash equivalents, trade receivables and
trade payables approximate their carrying values due to the
short-term nature of these instruments. Our cash, cash
equivalents, short-term and long-term investments and other
receivables are included in the table below:
| December 31, | ||||||||||||||||||||
| 2010 | 2009 | |||||||||||||||||||
|
Weighted-
|
Weighted-
|
|||||||||||||||||||
|
Average
|
Average
|
|||||||||||||||||||
|
Fair
|
Interest
|
Life
|
Fair
|
Interest
|
Life
|
|||||||||||||||
| Value | Rates | (Years) | Value | Rates | (Years) | |||||||||||||||
| (In thousands, except interest rates) | ||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 641,702 | 0% - .28% | 0.00 | $ | 927,815 | 0% - 1.55% | 0.00 | ||||||||||||
|
Short-term investments:
|
||||||||||||||||||||
|
Trading equity securities
|
19,630 | — | — | 24,014 | — | — | ||||||||||||||
|
Available-for-sale
equity securities
|
79,698 | — | — | 93,651 | — | — | ||||||||||||||
|
Available-for-sale
debt securities:
|
||||||||||||||||||||
|
Commercial paper and CDs
|
1,275 | .75% | .6 | 1,284 | .25% | .6 | ||||||||||||||
|
Corporate debt securities
|
52,022 | 10.01% - 13.99% | 3.6 | 33,852 | .38% -14.00% | 2.6 | ||||||||||||||
|
Mortgage-backed debt securities
|
372 | 2.79% | 2.7 | 861 | 5.15% - 5.18% | 3.0 | ||||||||||||||
|
Mortgage-CMO debt securities
|
3,015 | .42% - 5.9% | .3 | 5,411 | 2.58% -6.23% | 1.9 | ||||||||||||||
|
Asset-backed debt securities
|
3,476 | .56% - 4.81% | 1.3 | 3,963 | 2.64% -6.22% | 2.1 | ||||||||||||||
|
Total
available-for-sale
debt securities
|
60,160 | 45,371 | ||||||||||||||||||
|
Total
available-for-sale
securities
|
139,858 | 139,022 | ||||||||||||||||||
|
Total short-term investments
|
159,488 | 163,036 | ||||||||||||||||||
|
Long-term investments and other receivables:
|
||||||||||||||||||||
|
Actively managed funds
|
7,427 | N/A | 8,341 | N/A | ||||||||||||||||
|
Oil and gas financing receivables
|
32,873 | 13.10% - 13.52% | 92,541 | 13.10% -13.52% | ||||||||||||||||
|
Total long-term investments and other receivables
|
40,300 | 100,882 | ||||||||||||||||||
|
Total cash, cash equivalents, short-term and long-term
investments and other receivables
|
$ | 841,490 | $ | 1,191,733 | ||||||||||||||||
Our investments in debt securities listed in the above table and
a portion of our long-term investments are sensitive to changes
in interest rates. Additionally, our investment portfolio of
debt and equity securities, which are carried at fair value,
exposes us to price risk. A hypothetical 10% decrease in the
market prices for all securities as of December 31, 2010
would decrease the fair value of our trading securities and
available-for-sale
securities by $2.0 million and $14.0 million,
respectively.
61
Table of Contents
Table of Contents
the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers
LLP
Houston, Texas
March 1, 2011
64
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NABORS
INDUSTRIES LTD. AND SUBSIDIARIES
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands, except per share amounts) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 641,702 | $ | 927,815 | ||||
|
Short-term investments
|
159,488 | 163,036 | ||||||
|
Assets held for sale
|
352,048 | — | ||||||
|
Accounts receivable, net
|
1,116,510 | 724,040 | ||||||
|
Inventory
|
158,836 | 100,819 | ||||||
|
Deferred income taxes
|
31,510 | 125,163 | ||||||
|
Other current assets
|
152,836 | 135,791 | ||||||
|
Total current assets
|
2,612,930 | 2,176,664 | ||||||
|
Long-term investments and other receivables
|
40,300 | 100,882 | ||||||
|
Property, plant and equipment, net
|
7,815,419 | 7,646,050 | ||||||
|
Goodwill
|
494,372 | 164,265 | ||||||
|
Investment in unconsolidated affiliates
|
267,723 | 306,608 | ||||||
|
Other long-term assets
|
415,825 | 250,221 | ||||||
|
Total assets
|
$ | 11,646,569 | $ | 10,644,690 | ||||
| LIABILITIES AND EQUITY | ||||||||
|
Current liabilities:
|
||||||||
|
Current portion of long-term debt
|
$ | 1,379,018 | $ | 163 | ||||
|
Trade accounts payable
|
355,282 | 226,423 | ||||||
|
Accrued liabilities
|
394,292 | 346,337 | ||||||
|
Income taxes payable
|
25,788 | 35,699 | ||||||
|
Total current liabilities
|
2,154,380 | 608,622 | ||||||
|
Long-term debt
|
3,064,126 | 3,940,605 | ||||||
|
Other long-term liabilities
|
245,765 | 240,057 | ||||||
|
Deferred income taxes
|
770,247 | 673,427 | ||||||
|
Total liabilities
|
6,234,518 | 5,462,711 | ||||||
|
Commitments and contingencies (Note 17)
|
||||||||
|
Subsidiary preferred stock (Notes 7 and 14)
|
69,188 | — | ||||||
|
Equity:
|
||||||||
|
Shareholders’ equity:
|
||||||||
|
Common shares, par value $.001 per share:
|
||||||||
|
Authorized common shares 800,000; issued 315,034 and 313,915,
respectively
|
315 | 314 | ||||||
|
Capital in excess of par value
|
2,255,787 | 2,239,323 | ||||||
|
Accumulated other comprehensive income
|
342,052 | 292,706 | ||||||
|
Retained earnings
|
3,707,881 | 3,613,186 | ||||||
|
Less: treasury shares, at cost, 29,414 common shares
|
(977,873 | ) | (977,873 | ) | ||||
|
Total shareholders’ equity
|
5,328,162 | 5,167,656 | ||||||
|
Noncontrolling interest
|
14,701 | 14,323 | ||||||
|
Total equity
|
5,342,863 | 5,181,979 | ||||||
|
Total liabilities and equity
|
$ | 11,646,569 | $ | 10,644,690 | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
65
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NABORS
INDUSTRIES LTD. AND SUBSIDIARIES
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands, except per share amounts) | ||||||||||||
|
Revenues and other income:
|
||||||||||||
|
Operating revenues
|
$ | 4,174,635 | $ | 3,683,419 | $ | 5,507,542 | ||||||
|
Earnings (losses) from unconsolidated affiliates
|
33,257 | (155,433 | ) | (192,548 | ) | |||||||
|
Investment income (loss)
|
7,648 | 25,599 | 21,412 | |||||||||
|
Total revenues and other income
|
4,215,540 | 3,553,585 | 5,336,406 | |||||||||
|
Costs and other deductions:
|
||||||||||||
|
Direct costs
|
2,423,602 | 2,001,404 | 3,100,613 | |||||||||
|
General and administrative expenses
|
346,661 | 428,161 | 479,194 | |||||||||
|
Depreciation and amortization
|
764,253 | 667,100 | 614,367 | |||||||||
|
Depletion
|
17,943 | 9,417 | 22,308 | |||||||||
|
Interest expense
|
273,044 | 266,039 | 196,718 | |||||||||
|
Losses (gains) on sales and retirements of long-lived assets and
other expense (income), net
|
47,060 | 12,559 | 15,829 | |||||||||
|
Impairments and other charges
|
260,931 | 330,976 | 176,123 | |||||||||
|
Total costs and other deductions
|
4,133,494 | 3,715,656 | 4,605,152 | |||||||||
|
Income (loss) from continuing operations before income taxes
|
82,046 | (162,071 | ) | 731,254 | ||||||||
|
Income tax expense (benefit):
|
||||||||||||
|
Current
|
(83,816 | ) | 69,532 | 188,832 | ||||||||
|
Deferred
|
59,002 | (203,335 | ) | 20,828 | ||||||||
|
Total income tax expense (benefit)
|
(24,814 | ) | (133,803 | ) | 209,660 | |||||||
|
Subsidiary preferred stock dividend
|
750 | — | — | |||||||||
|
Income (loss) from continuing operations, net of tax
|
106,110 | (28,268 | ) | 521,594 | ||||||||
|
Income (loss) from discontinued operations, net of tax
|
(11,330 | ) | (57,620 | ) | (41,930 | ) | ||||||
|
Net income (loss)
|
94,780 | (85,888 | ) | 479,664 | ||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
(85 | ) | 342 | (3,927 | ) | |||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | $ | (85,546 | ) | $ | 475,737 | |||||
|
Earnings (losses) per share:
|
||||||||||||
|
Basic from continuing operations
|
$ | .37 | $ | (.10 | ) | $ | 1.84 | |||||
|
Basic from discontinued operations
|
(.04 | ) | (.20 | ) | (.15 | ) | ||||||
|
Total Basic
|
$ | .33 | $ | (.30 | ) | $ | 1.69 | |||||
|
Diluted from continuing operations
|
$ | .37 | $ | (.10 | ) | $ | 1.80 | |||||
|
Diluted from discontinued operations
|
(.04 | ) | (.20 | ) | (.15 | ) | ||||||
|
Total Diluted
|
$ | .33 | $ | (.30 | ) | $ | 1.65 | |||||
|
Weighted-average number of common shares outstanding:
|
||||||||||||
|
Basic
|
285,145 | 283,326 | 281,622 | |||||||||
|
Diluted
|
289,996 | 283,326 | 288,236 | |||||||||
The details of credit-related impairments to investments for
the year ended December 31, 2009 is presented below:
| (In thousands) | ||||
|
Other-than-temporary
impairment on debt security
|
$ | 40,300 | ||
|
Less:
other-than-temporary
impairment recognized in accumulated other comprehensive income
(loss)
|
(4,651 | ) | ||
|
Credit-related impairment on investment(1)
|
$ | 35,649 | ||
| (1) | Included in Impairments and other charges (Note 3) |
The accompanying notes are an integral part of these
consolidated financial statements.
66
Table of Contents
NABORS
INDUSTRIES LTD. AND SUBSIDIARIES
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | $ | (85,546 | ) | $ | 475,737 | |||||
|
Adjustments to net income (loss):
|
||||||||||||
|
Depreciation and amortization
|
766,519 | 668,415 | 614,367 | |||||||||
|
Depletion
|
27,002 | 11,078 | 25,442 | |||||||||
|
Deferred income tax expense (benefit)
|
55,964 | (218,760 | ) | 17,315 | ||||||||
|
Deferred financing costs amortization
|
5,431 | 6,133 | 7,661 | |||||||||
|
Pension liability amortization and adjustments
|
664 | 844 | 160 | |||||||||
|
Discount amortization on long-term debt
|
70,719 | 86,802 | 123,739 | |||||||||
|
Amortization of loss on hedges
|
786 | 580 | 548 | |||||||||
|
Impairments and other charges
|
260,931 | 339,129 | 176,123 | |||||||||
|
Losses (gains) on long-lived assets, net
|
(1,050 | ) | 12,339 | 9,644 | ||||||||
|
Losses (gains) on investments, net
|
191 | (9,954 | ) | 18,736 | ||||||||
|
Losses (gains) on debt retirement, net
|
7,042 | (11,197 | ) | (12,248 | ) | |||||||
|
Losses (gains) on derivative instruments
|
2,471 | 338 | 4,783 | |||||||||
|
Share-based compensation
|
13,746 | 106,725 | 45,401 | |||||||||
|
Foreign currency transaction losses (gains), net
|
17,880 | 8,372 | (2,718 | ) | ||||||||
|
Equity in (earnings) losses of unconsolidated affiliates, net of
dividends
|
(13,630 | ) | 229,813 | 236,763 | ||||||||
|
Changes in operating assets and liabilities, net of effects from
acquisitions:
|
||||||||||||
|
Accounts receivable
|
(249,725 | ) | 450,530 | (157,697 | ) | |||||||
|
Inventory
|
(15,201 | ) | 52,995 | (26,774 | ) | |||||||
|
Other current assets
|
6,589 | 205,108 | (81,764 | ) | ||||||||
|
Other long-term assets
|
7,509 | (22,233 | ) | (85,231 | ) | |||||||
|
Trade accounts payable and accrued liabilities
|
70,463 | (146,470 | ) | 38,129 | ||||||||
|
Income taxes payable
|
(19,208 | ) | (62,535 | ) | 24,043 | |||||||
|
Other long-term liabilities
|
(2,804 | ) | (5,534 | ) | 10,665 | |||||||
|
Net cash provided by operating activities
|
1,106,984 | 1,616,972 | 1,462,824 | |||||||||
|
Cash flows from investing activities:
|
||||||||||||
|
Purchases of investments
|
(34,147 | ) | (32,674 | ) | (269,983 | ) | ||||||
|
Sales and maturities of investments
|
34,613 | 57,033 | 521,613 | |||||||||
|
Cash paid for acquisition of businesses, net of cash acquired
|
(733,630 | ) | — | (287 | ) | |||||||
|
Investment in unconsolidated affiliates
|
(40,936 | ) | (125,076 | ) | (271,309 | ) | ||||||
|
Capital expenditures
|
(930,277 | ) | (1,093,435 | ) | (1,506,979 | ) | ||||||
|
Proceeds from sales of assets and insurance claims
|
31,072 | 31,375 | 69,842 | |||||||||
|
Net cash used for investing activities
|
(1,673,305 | ) | (1,162,777 | ) | (1,457,103 | ) | ||||||
|
Cash flows from financing activities:
|
||||||||||||
|
Increase (decrease) in cash overdrafts
|
(6,298 | ) | (18,157 | ) | 23,858 | |||||||
|
Proceeds from long-term debt
|
696,948 | 1,124,978 | 962,901 | |||||||||
|
Debt issuance costs
|
(8,934 | ) | (8,832 | ) | (7,324 | ) | ||||||
|
Payments for (proceeds from) hedge transactions
|
(5,667 | ) | — | — | ||||||||
|
Proceeds from Revolving Credit Facility
|
600,000 | — | — | |||||||||
|
Proceeds from issuance of common shares
|
8,201 | 11,249 | 56,630 | |||||||||
|
Reduction in long-term debt
|
(398,514 | ) | (1,081,801 | ) | (836,511 | ) | ||||||
|
Reduction in Revolving Credit Facility
|
(600,000 | ) | — | — | ||||||||
|
Repurchase of equity component of convertible debt
|
(4,712 | ) | (6,586 | ) | — | |||||||
|
Settlement of call options and warrants, net
|
1,134 | — | — | |||||||||
|
Repurchase of common shares
|
— | — | (281,101 | ) | ||||||||
|
Purchase of restricted stock
|
(1,935 | ) | (1,515 | ) | (13,061 | ) | ||||||
|
Tax benefit related to share-based awards
|
31 | 37 | 5,369 | |||||||||
|
Net cash provided by (used for) financing activities
|
280,254 | 19,373 | (89,239 | ) | ||||||||
|
Effect of exchange rate changes on cash and cash equivalents
|
(46 | ) | 12,160 | (5,701 | ) | |||||||
|
Net increase in cash and cash equivalents
|
(286,113 | ) | 485,728 | (89,219 | ) | |||||||
|
Cash and cash equivalents, beginning of period
|
927,815 | 442,087 | 531,306 | |||||||||
|
Cash and cash equivalents, end of period
|
$ | 641,702 | $ | 927,815 | $ | 442,087 | ||||||
The accompanying notes are an integral part of these
consolidated financial statements.
67
Table of Contents
NABORS
INDUSTRIES LTD. AND SUBSIDIARIES
|
Accumulated
|
||||||||||||||||||||||||||||||||||||
|
Capital in
|
Other
|
Non-
|
||||||||||||||||||||||||||||||||||
| Common Shares |
Excess of
|
Comprehensive
|
Retained
|
Treasury
|
Controlling
|
Total
|
||||||||||||||||||||||||||||||
| Shares | Par Value | Par Value | Income | Earnings | Shares | Interest | Equity | |||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||
|
Balances, December 31, 2007
|
305,458 | $ | 305 | $ | 2,133,579 | $ | 322,635 | $ | 3,222,995 | $ | (877,935 | ) | $ | 14,468 | $ | 4,816,047 | ||||||||||||||||||||
|
Comprehensive income (loss):
|
||||||||||||||||||||||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 475,737 | 475,737 | 475,737 | ||||||||||||||||||||||||||||||||
|
Translation adjustment attributable to Nabors
|
(228,865 | ) | (228,865 | ) | (228,865 | ) | ||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) on marketable securities, net of
income tax benefit of $4,374
|
(37,190 | ) | (37,190 | ) | (37,190 | ) | ||||||||||||||||||||||||||||||
|
Less: Reclassification adjustment for (gains)/losses included in
net income (loss), net of income taxes of $129
|
(51 | ) | (51 | ) | (51 | ) | ||||||||||||||||||||||||||||||
|
Pension liability amortization, net of income taxes of $56
|
104 | 104 | 104 | |||||||||||||||||||||||||||||||||
|
Pension liability adjustment, net of income tax benefit of $1,915
|
(3,009 | ) | (3,009 | ) | (3,009 | ) | ||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) and amortization of (gains)/losses on
cash flow hedges, net of income taxes of $163
|
(104 | ) | (104 | ) | (104 | ) | ||||||||||||||||||||||||||||||
|
Comprehensive income (loss) attributable to Nabors
|
$ | 206,622 | ||||||||||||||||||||||||||||||||||
|
Net income (loss) attributable to noncontrolling interest
|
3,927 | 3,927 | 3,927 | |||||||||||||||||||||||||||||||||
|
Translation adjustment attributable to noncontrolling interest
|
(2,537 | ) | (2,537 | ) | (2,537 | ) | ||||||||||||||||||||||||||||||
|
Comprehensive income (loss) attributable to noncontrolling
interest
|
1,390 | |||||||||||||||||||||||||||||||||||
|
Total comprehensive income (loss)
|
$ | 208,012 | ||||||||||||||||||||||||||||||||||
|
Issuance of common shares for stock options exercised, net of
surrender of unexercised stock options
|
2,480 | 2 | 56,628 | 56,630 | ||||||||||||||||||||||||||||||||
|
Distributions from noncontrolling interest
|
(1,540 | ) | (1,540 | ) | ||||||||||||||||||||||||||||||||
|
Nabors Exchangeco shares exchanged
|
16 | — | ||||||||||||||||||||||||||||||||||
|
Issuance of 5,246 treasury shares related to conversion of notes
|
(181,163 | ) | 181,163 | — | ||||||||||||||||||||||||||||||||
|
Repurchase of 8,538 treasury shares
|
(281,101 | ) | (281,101 | ) | ||||||||||||||||||||||||||||||||
|
Repurchase of equity component of convertible debt
|
(35 | ) | (35 | ) | ||||||||||||||||||||||||||||||||
|
Tax benefit related to the redemption of convertible debt
|
81,789 | 81,789 | ||||||||||||||||||||||||||||||||||
|
Tax benefit related to share-based awards
|
6,282 | 6,282 | ||||||||||||||||||||||||||||||||||
|
Restricted stock awards, net
|
4,389 | 5 | (13,066 | ) | (13,061 | ) | ||||||||||||||||||||||||||||||
|
Share-based compensation
|
45,401 | 45,401 | ||||||||||||||||||||||||||||||||||
|
Balances, December 31, 2008
|
312,343 | $ | 312 | $ | 2,129,415 | $ | 53,520 | $ | 3,698,732 | $ | (977,873 | ) | $ | 14,318 | $ | 4,918,424 | ||||||||||||||||||||
|
Balances, December 31, 2008
|
312,343 | $ | 312 | $ | 2,129,415 | $ | 53,520 | $ | 3,698,732 | $ | (977,873 | ) | $ | 14,318 | $ | 4,918,424 | ||||||||||||||||||||
|
Comprehensive income (loss):
|
||||||||||||||||||||||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | (85,546 | ) | (85,546 | ) | (85,546 | ) | |||||||||||||||||||||||||||||
|
Translation adjustment attributable to Nabors
|
150,290 | 150,290 | 150,290 | |||||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) on marketable securities, net of
income benefit of $839
|
36,727 | 36,727 | 36,727 | |||||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) on adjusted basis for marketable debt
security, net of income taxes of $1,199
|
1,956 | 1,956 | 1,956 | |||||||||||||||||||||||||||||||||
|
Less: Reclassification adjustment for (gains)/losses included in
net income (loss), net of income tax benefit of $4,921
|
49,386 | 49,386 | 49,386 | |||||||||||||||||||||||||||||||||
|
Pension liability amortization, net of income taxes of $325
|
519 | 519 | 519 | |||||||||||||||||||||||||||||||||
|
Pension liability adjustment, net of income taxes of $89
|
130 | 130 | 130 | |||||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) and amortization of (gains)/losses on
cash flow hedges, net of income tax benefit of $18
|
178 | 178 | 178 | |||||||||||||||||||||||||||||||||
|
Comprehensive income (loss) attributable to Nabors
|
$ | 153,640 | ||||||||||||||||||||||||||||||||||
|
Net income (loss) attributable to noncontrolling interest
|
(342 | ) | (342 | ) | (342 | ) | ||||||||||||||||||||||||||||||
|
Translation adjustment attributable to noncontrolling interest
|
2,024 | 2,024 | 2,024 | |||||||||||||||||||||||||||||||||
|
Comprehensive income (loss) attributable to noncontrolling
interest
|
1,682 | |||||||||||||||||||||||||||||||||||
|
Total comprehensive income (loss)
|
$ | 155,322 | ||||||||||||||||||||||||||||||||||
|
Issuance of common shares for stock options exercised, net of
surrender of unexercised stock options
|
1,476 | 2 | 11,247 | 11,249 | ||||||||||||||||||||||||||||||||
|
Distributions from noncontrolling interest
|
(1,677 | ) | (1,677 | ) | ||||||||||||||||||||||||||||||||
|
Nabors Exchangeco shares exchanged
|
105 | — | ||||||||||||||||||||||||||||||||||
|
Repurchase of equity component of convertible debt
|
(6,586 | ) | (6,586 | ) | ||||||||||||||||||||||||||||||||
|
Tax benefit related to share-based awards
|
37 | 37 | ||||||||||||||||||||||||||||||||||
|
Restricted stock awards, net
|
(9 | ) | (1,515 | ) | (1,515 | ) | ||||||||||||||||||||||||||||||
|
Share-based compensation
|
106,725 | 106,725 | ||||||||||||||||||||||||||||||||||
|
Balances, December 31, 2009
|
313,915 | $ | 314 | $ | 2,239,323 | $ | 292,706 | $ | 3,613,186 | $ | (977,873 | ) | $ | 14,323 | $ | 5,181,979 | ||||||||||||||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
68
Table of Contents
NABORS
INDUSTRIES LTD. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CHANGES IN EQUITY
— (Continued)
|
Accumulated
|
||||||||||||||||||||||||||||||||||||
|
Capital in
|
Other
|
Non-
|
||||||||||||||||||||||||||||||||||
| Common Shares |
Excess of
|
Comprehensive
|
Retained
|
Treasury
|
Controlling
|
Total
|
||||||||||||||||||||||||||||||
| Shares | Par Value | Par Value | Income | Earnings | Shares | Interest | Equity | |||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||
|
Balances, December 31, 2009
|
313,915 | $ | 314 | $ | 2,239,323 | $ | 292,706 | $ | 3,613,186 | $ | (977,873 | ) | $ | 14,323 | $ | 5,181,979 | ||||||||||||||||||||
|
Comprehensive income (loss):
|
||||||||||||||||||||||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | 94,695 | 94,695 | ||||||||||||||||||||||||||||||||
|
Translation adjustment attributable to Nabors
|
60,897 | 60,897 | 60,897 | |||||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) on marketable securities, net of
income taxes of $7,435
|
(7,157 | ) | (7,157 | ) | (7,157 | ) | ||||||||||||||||||||||||||||||
|
Less: Reclassification adjustment for (gains)/losses included in
net income (loss), net of income taxes of $693
|
(1,001 | ) | (1,001 | ) | (1,001 | ) | ||||||||||||||||||||||||||||||
|
Pension liability amortization, net of income taxes of $259
|
405 | 405 | 405 | |||||||||||||||||||||||||||||||||
|
Pension liability adjustment, net of income tax benefit of $405
|
(635 | ) | (635 | ) | (635 | ) | ||||||||||||||||||||||||||||||
|
Unrealized gains/(losses) and amortization of (gains)/losses on
cash flow hedges, net of income tax benefit of $2,119
|
(3,163 | ) | (3,163 | ) | (3,163 | ) | ||||||||||||||||||||||||||||||
|
Comprehensive income (loss) attributable to Nabors
|
$ | 144,041 | ||||||||||||||||||||||||||||||||||
|
Net income (loss) attributable to noncontrolling interest
|
85 | 85 | 85 | |||||||||||||||||||||||||||||||||
|
Translation adjustment attributable to noncontrolling interest
|
723 | 723 | 723 | |||||||||||||||||||||||||||||||||
|
Comprehensive income (loss) attributable to noncontrolling
interest
|
808 | |||||||||||||||||||||||||||||||||||
|
Total comprehensive income (loss)
|
$ | 144,849 | ||||||||||||||||||||||||||||||||||
|
Issuance of common shares for stock options exercised, net of
surrender of unexercised stock options
|
714 | 1 | 8,200 | 8,201 | ||||||||||||||||||||||||||||||||
|
Distributions from noncontrolling interest
|
(867 | ) | (867 | ) | ||||||||||||||||||||||||||||||||
|
Contributions to noncontrolling interest
|
437 | 437 | ||||||||||||||||||||||||||||||||||
|
Repurchase of equity component of convertible debt
|
(4,712 | ) | (4,712 | ) | ||||||||||||||||||||||||||||||||
|
Settlement of call options and warrants, net
|
1,134 | 1,134 | ||||||||||||||||||||||||||||||||||
|
Tax benefit related to share-based awards
|
31 | 31 | ||||||||||||||||||||||||||||||||||
|
Restricted stock awards, net
|
405 | (1,935 | ) | (1,935 | ) | |||||||||||||||||||||||||||||||
|
Share-based compensation
|
13,746 | 13,746 | ||||||||||||||||||||||||||||||||||
|
Balances, December 31, 2010
|
315,034 | $ | 315 | $ | 2,255,787 | $ | 342,052 | $ | 3,707,881 | $ | (977,873 | ) | $ | 14,701 | $ | 5,342,863 | ||||||||||||||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
69
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
| Note 1 | Nature of Operations |
Nabors is the largest land drilling contractor in the world and
one of the largest land well-servicing and workover contractors
in the United States and Canada:
| • | We actively market approximately 550 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. | |
| • | We actively market approximately 555 rigs for land well-servicing and workover work in the United States and approximately 172 rigs for land workover and well-servicing work in Canada. |
We are also a leading provider of offshore platform workover and
drilling rigs, and actively market 37 platform, 13
jack-up
and
three barge rigs in the United States, including the Gulf of
Mexico, and multiple international markets.
In addition to the foregoing services:
| • | We offer a wide range of ancillary well-site services, including hydraulic fracturing, engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select United States and international markets. | |
| • | We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software. | |
| • | We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests. | |
| • | We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets nine rigs in addition to the rigs we lease to the joint venture. | |
| • | We also provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft. |
The majority of our business is conducted through our various
Contract Drilling operating segments, which include our
drilling, well-servicing, fluid logistics and workover
operations, on land and offshore. Our oil and gas exploration,
development and production operations are included in our Oil
and Gas operating segment. Our operating segments engaged in
drilling technology and top drive manufacturing, directional
drilling, rig instrumentation and software, and construction and
logistics operations are aggregated in our Other Operating
Segments.
On September 10, 2010, we acquired through a tender offer
and merger transaction (the “Superior Merger”), all of
the outstanding common stock of Superior Well Services, Inc.
(“Superior”). Superior provides a wide range of
wellsite solutions to oil and natural gas companies, consisting
primarily of technical pumping services, including hydraulic
fracturing, a process sometimes used in the completion of oil
and gas wells whereby water, sand and chemicals are injected
under pressure into subsurface formations to stimulate gas and,
to a lesser extent, oil production, and downhole surveying
services. The effects of the Superior Merger and the operating
results of Superior from the acquisition date to
December 31, 2010 are included in the accompanying audited
consolidated financial statements and are reflected in our
operating segment titled “Pressure Pumping.” See
Note 7 — Acquisitions and Divestitures for
additional information.
During 2010, we began actively marketing our oil and gas assets
in the Horn River basin in Canada and in the Llanos basin in
Colombia. These assets also include our 49.7% and 50.0%
ownership interests in our investments of Remora Energy
International LP (“Remora”) and Stone Mountain Venture
Partnership
70
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
(“SMVP”), respectively, which we account for using the
equity method of accounting. We determined that the plan of sale
criteria in the ASC Topic relating to the Presentation of
Financial Statements for Assets Sold or Held for Sale had been
met during the third quarter of 2010. Accordingly, the
accompanying consolidated statements of income (loss), and
certain accompanying notes to the consolidated financial
statements, have been updated to retroactively reclassify the
operating results of these assets, as discontinued operations
for all periods presented. See Note 21 —
Discontinued Operations for additional discussion.
The consolidated financial statements and related footnotes are
presented in accordance with accounting principles generally
accepted in the United States of America (“GAAP”).
Certain reclassifications have been made to prior periods to
conform to the current period presentation, with no effect on
our consolidated financial position, results of operations or
cash flows.
| Note 2 | Summary of Significant Accounting Policies |
Principles
of Consolidation
Our consolidated financial statements include the accounts of
Nabors, as well as all majority owned and non-majority owned
subsidiaries required to be consolidated under GAAP. Our
consolidated financial statements exclude majority owned
entities for which we do not have either (1) the ability to
control the operating and financial decisions and policies of
that entity or (2) a controlling financial interest in a
variable interest entity. All significant intercompany accounts
and transactions are eliminated in consolidation.
Investments in operating entities where we have the ability to
exert significant influence, but where we do not control
operating and financial policies, are accounted for using the
equity method. Our share of the net income (loss) of these
entities is recorded as earnings (losses) from unconsolidated
affiliates in our consolidated statements of income (loss), and
our investment in these entities is included as a single amount
in our consolidated balance sheets. Investments in
unconsolidated affiliates accounted for using the equity method
totaled $265.8 million and $305.7 million and
investments in unconsolidated affiliates accounted for using the
cost method totaled $1.9 million and $.9 million as of
December 31, 2010 and 2009, respectively. At
December 31, 2010, assets held for sale include investments
in unconsolidated affiliates accounted for using the equity
method totaling $79.5 million. See Note 21 —
Discontinued Operations for additional information.
Similarly, we have investments in offshore funds, which are
classified as long-term investments and are accounted for using
the equity method of accounting based on our ownership interest
in each fund.
Cash
and Cash Equivalents
Cash and cash equivalents include demand deposits and various
other short-term investments with original maturities of three
months or less.
Investments
Short-term
investments
Short-term investments consist of equity securities,
certificates of deposit, corporate debt securities,
mortgage-backed debt securities and asset-backed debt
securities. Securities classified as
available-for-sale
or trading are stated at fair value. Unrealized holding gains
and temporary losses for
available-for-sale
securities are excluded from earnings and, until realized, are
reported net of taxes in a separate component of equity.
Unrealized holding losses are included in earnings during the
period for which the loss is determined to be
other-than-temporary.
Gains and losses from changes in the market value of securities
classified as trading are reported in earnings currently.
71
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In computing realized gains and losses on the sale of equity
securities, the specific-identification method is used. In
accordance with this method, the cost of the equity securities
sold is determined using the specific cost of the security when
originally purchased.
Long-term
investments and other receivables
Our oil and gas financing receivables are classified as
long-term investments. These receivables represent our financing
agreements for certain production payment contracts in our Oil
and Gas segment. We have also invested in overseas funds that
invest primarily in a variety of public and private
U.S. and
non-U.S. securities
(including asset-backed and mortgage-backed securities, global
structured-asset securitizations, whole-loan mortgages, and
participations in whole loans and whole-loan mortgages). These
investments are non-marketable and do not have published fair
values. We account for these funds under the equity method of
accounting based on our percentage ownership interest and
recognize gains or losses as investment income (loss), currently
based on changes in the net asset value of our investment during
the current period.
Inventory
Inventory is stated at the lower of cost or market. Cost is
determined using the
first-in,
first-out method and includes the cost of materials, labor and
manufacturing overhead. Inventory was comprised of approximately
$81.3 million in raw materials, $23.6 million in
work-in-progress
and $53.9 million in finished goods at December 31,
2010.
Property,
Plant and Equipment
Property, plant and equipment, including renewals and
betterments, are stated at cost, while maintenance and repairs
are expensed currently. Interest costs applicable to the
construction of qualifying assets are capitalized as a component
of the cost of such assets. We provide for the depreciation of
our drilling and workover rigs using the
units-of-production
method. For each day a rig is operating, we depreciate it over
an approximate 4,900-day period, with the exception of our
jack-up
rigs
which are depreciated over an 8,030-day period, after provision
for salvage value. For each day a rig asset is not operating, it
is depreciated over an assumed depreciable life of
20 years, with the exception of our
jack-up
rigs, where a
30-year
depreciable life is used, after provision for salvage value.
Depreciation on our buildings, well-servicing rigs, oilfield
hauling and mobile equipment, marine transportation and supply
vessels, aircraft equipment, and other machinery and equipment
is computed using the straight-line method over the estimated
useful life of the asset after provision for salvage value
(buildings — 10 to 30 years; well-servicing
rigs — 3 to 15 years; marine transportation and
supply vessels — 10 to 25 years; aircraft
equipment — 5 to 20 years; oilfield hauling and
mobile equipment and other machinery and equipment — 3
to 10 years). Amortization of capitalized leases is
included in depreciation and amortization expense. Upon
retirement or other disposal of fixed assets, the cost and
related accumulated depreciation are removed from the respective
accounts and any gains or losses are included in our results of
operations.
We review our assets for impairment when events or changes in
circumstances indicate that the carrying amounts of property,
plant and equipment may not be recoverable. An impairment loss
is recorded in the period in which it is determined that the sum
of estimated future cash flows, on an undiscounted basis, is
less than the carrying amount of the long-lived asset.
Impairment charges are recorded using discounted cash flows
which requires the estimation of dayrates and utilization, and
such estimates can change based on market conditions,
technological advances in the industry or changes in regulations
governing the industry. Significant and unanticipated changes to
the assumptions could result in future impairments. A
significantly prolonged period of lower oil and natural gas
prices could continue to adversely affect the demand for and
prices of our services, which could result in future impairment
charges. As the determination of whether impairment charges
72
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
should be recorded on our long-lived assets is subject to
significant management judgment and an impairment of these
assets could result in a material charge on our consolidated
statements of income (loss), management believes that accounting
estimates related to impairment of long-lived assets are
critical.
Oil
and Gas Properties
We follow the successful-efforts method of accounting for our
consolidated subsidiaries’ oil and gas activities. Under
the successful-efforts method, lease acquisition costs and all
development costs are capitalized. Our provision for depletion
is based on these capitalized costs and is determined on a
property-by-property
basis using the
units-of-production
method. Proved property acquisition costs are amortized over
total proved reserves. Costs of wells and related equipment and
facilities are amortized over the life of proved developed
reserves. Estimated fair value of proved and unproved properties
includes the estimated present value of all reasonably expected
future production, prices and costs. Proved oil and gas
properties are reviewed when circumstances suggest the need for
such a review and, are written down to their estimated fair
value, if required. Unproved properties are reviewed to
determine if there has been impairment of the carrying value and
when circumstances suggest an impairment has occurred, are
written down to their estimated fair value in that period. We
consider the fair value estimates a Level 3 fair value
measurement. The estimated fair value of our proved reserves
generally declines when there is a significant and sustained
decline in oil and natural gas prices. During 2010, 2009 and
2008, our impairment tests on the wholly owned oil and gas
assets of our Oil and Gas operating segment resulted in
impairment charges of $137.8 million, $48.6 million
and $21.5 million, respectively. As further discussed below
in
Recent Accounting Pronouncements
, we adopted new
guidance relating to the manner in which our oil and gas
reserves are estimated as of December 31, 2009.
Exploratory drilling costs are capitalized until the results are
determined. If proved reserves are not discovered, the
exploratory drilling costs are expensed. Interest costs related
to financing major oil and gas projects in progress are
capitalized until the projects are evaluated or until the
projects are substantially complete and ready for their intended
use if the projects are evaluated as successful. Other
exploratory costs are expensed as incurred.
Our unconsolidated oil and gas joint ventures, which we account
for under the equity method of accounting, utilize the full-cost
method of accounting for costs related to oil and natural gas
properties. Under this method, all such costs (for both
productive and nonproductive properties) are capitalized and
amortized on an aggregate basis over the estimated lives of the
properties using the
units-of-production
method. However, these capitalized costs are subject to a
ceiling test which limits pooled costs to the aggregate of the
present value of future net revenues attributable to proved oil
and natural gas reserves, discounted at 10%, plus the lower of
cost or market value of unproved properties. As further
discussed below in
Recent Accounting Pronouncements
and
in relation to the full-cost ceiling test, our unconsolidated
oil and gas joint ventures changed the manner in which their oil
and gas reserves are estimated and the manner in which they
calculate the ceiling limit on capitalized oil and gas costs as
of December 31, 2009. Under the new guidance, future
revenues for purposes of the ceiling test are valued using a
12-month
average price, adjusted for the impact of derivatives accounted
for as cash flow hedges as prescribed by the Securities and
Exchange Commission (“SEC”) rules. No full-cost
ceiling test writedowns were recorded by our unconsolidated oil
and gas joint ventures during 2010. During 2009, our
proportionate share of those ventures’ full-cost ceiling
test writedowns was $237.1 million.
During 2008, our unconsolidated oil and gas joint ventures
evaluated the full-cost ceiling using then-current prices for
oil and natural gas, adjusted for the impact of derivatives
accounted for as cash flow hedges. As a result, our
proportionate share of those ventures’ full-cost ceiling
test writedowns was $228.3 million.
A significantly prolonged period of lower oil and natural gas
prices or a reduction to the estimation of reserve quantities
could continue to result in future impairment charges to our oil
and gas properties.
73
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Oil and
Gas Reserves
Evaluations of oil and gas reserves are integral to making
investment decisions about oil and gas properties such as
whether development should proceed. Oil and gas reserve
quantities are also used as the basis for calculating
unit-of-production
depreciation rates and for evaluating impairment. Oil and gas
reserves include both proved and unproved reserves. Consistent
with the definitions provided by the SEC, proved oil and gas
reserves are those quantities of oil and gas, which, by analysis
of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible from a given
date forward, known reservoirs, and under existing economic
conditions. Unproved reserves are those with less than
reasonable certainty of recoverability and include probable
reserves. Probable reserves are reserves that are more likely to
be recovered than not.
Estimation of proved reserves, which is based on the requirement
of reasonable certainty, is an ongoing process involving
rigorous technical evaluations, commercial and market
assessment, and detailed analysis of well information such as
flow rates and reservoir pressure declines. Although we are
reasonably certain that proved reserves will be produced, the
timing and amount recovered can be affected by a number of
factors including completion of development projects, reservoir
performance, regulatory approvals and significant changes in
long-term oil and gas price levels.
Goodwill
Goodwill represents the cost in excess of fair value of the net
assets of companies acquired. We review goodwill and intangible
assets with indefinite lives for impairment annually or more
frequently if events or changes in circumstances indicate that
the carrying amount of the reporting unit exceeds its fair
value. A significantly prolonged period of lower oil and natural
gas prices could continue to adversely affect the demand for and
prices of our services, which could result in future goodwill
impairment charges for other reporting units due to the
potential impact on our estimate of our future operating
results. See Note 3 — Impairments and Other
Charges for discussion of goodwill impairments.
The change in the carrying amount of goodwill for our various
Contract Drilling segments and our Other Operating Segments for
the years ended December 31, 2010 and 2009 was as follows:
|
Acquisitions
|
||||||||||||||||||||||||
|
and
|
||||||||||||||||||||||||
|
Balance as of
|
Purchase
|
Cumulative
|
Balance as of
|
|||||||||||||||||||||
|
December 31,
|
Price
|
Translation
|
December 31,
|
|||||||||||||||||||||
| 2008 | Adjustments | Impairments | Adjustment | 2009 | ||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Contract Drilling:
|
||||||||||||||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 30,154 | $ | — | $ | — | $ | — | $ | 30,154 | ||||||||||||||
|
U.S. Land Well-servicing
|
50,839 | — | — | — | 50,839 | |||||||||||||||||||
|
U.S. Offshore
|
18,003 | — | — | — | 18,003 | |||||||||||||||||||
|
Alaska
|
19,995 | — | — | — | 19,995 | |||||||||||||||||||
|
International
|
18,983 | — | — | — | 18,983 | |||||||||||||||||||
|
Subtotal Contract Drilling
|
137,974 | — | — | — | 137,974 | |||||||||||||||||||
|
Other Operating Segments
|
37,775 | — | (14,689 | )(1) | 3,205 | 26,291 | ||||||||||||||||||
|
Total
|
$ | 175,749 | $ | — | $ | (14,689 | ) | $ | 3,205 | $ | 164,265 | |||||||||||||
74
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Balance as of
|
Acquisitions and
|
Cumulative
|
Balance as of
|
|||||||||||||||||||||
|
December 31,
|
Purchase Price
|
Translation
|
December 31,
|
|||||||||||||||||||||
| 2009 | Adjustments | Impairments | Adjustment | 2010 | ||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Contract Drilling:
|
||||||||||||||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 30,154 | $ | — | $ | — | $ | — | $ | 30,154 | ||||||||||||||
|
U.S. Land Well-servicing
|
50,839 | 5,000 | (2) | — | — | 55,839 | ||||||||||||||||||
|
Pressure Pumping
|
— | 334,992 | (3) | — | — | 334,992 | ||||||||||||||||||
|
U.S. Offshore
|
18,003 | — | (10,707 | )(4) | — | 7,296 | ||||||||||||||||||
|
Alaska
|
19,995 | — | — | — | 19,995 | |||||||||||||||||||
|
International
|
18,983 | — | — | — | 18,983 | |||||||||||||||||||
|
Subtotal Contract Drilling
|
137,974 | 339,992 | (10,707 | ) | — | 467,259 | ||||||||||||||||||
|
Other Operating Segments
|
26,291 | — | — | 822 | 27,113 | |||||||||||||||||||
|
Total
|
$ | 164,265 | $ | 339,992 | $ | (10,707 | ) | $ | 822 | $ | 494,372 | |||||||||||||
| (1) | Represents goodwill impairment associated with Nabors Blue Sky Ltd., a Canadian subsidiary, included in our Other Operating segment. The impairment charges to Nabors Blue Sky were deemed necessary due to the continued deterioration of the downturn in the oil and gas industry in Canada which has led to diminished demand for immediate heliportable access to remote drilling sites. As of December 31, 2009, Nabors Blue Sky Ltd. has no recorded goodwill. | |
| (2) | Represents the preliminary calculations of goodwill recorded in connection with our acquisition of Energy Contractors LLC (“Energy Contractors”). See Note 7 — Acquisitions and Divestitures for additional discussion. | |
| (3) | Represents the goodwill recorded in connection with our acquisition of Superior. See Note 7 — Acquisitions and Divestitures for additional discussion. | |
| (4) | Represents goodwill impairment associated with our U.S. Offshore operating segment. The impairment charge was deemed necessary due to the uncertainty of utilization of some of our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. See Note 3 — Impairments and other charges for additional information. |
Our Oil and Gas segment does not have any goodwill. Goodwill for
the consolidated company, totaling approximately
$6.5 million, is expected to be deductible for tax purposes.
Derivative
Financial Instruments
We record derivative financial instruments (including certain
derivative instruments embedded in other contracts) in our
consolidated balance sheets at fair value as either assets or
liabilities. The accounting for changes in the fair value of a
derivative instrument depends on the intended use of the
derivative and the resulting designation, which is established
at the inception of a derivative. Accounting for derivatives
qualifying as fair value hedges allows a derivative’s gains
and losses to offset related results on the hedged item in the
statement of income. For derivative instruments designated as
cash flow hedges, changes in fair value, to the extent the hedge
is effective, are recognized in other comprehensive income until
the hedged item is recognized in earnings. Hedge effectiveness
is measured quarterly based on the relative cumulative changes
in fair value between the derivative contract and the hedged
item over time. Any change in fair value resulting from
ineffectiveness is recognized immediately in earnings. Any
change in fair value of derivative financial instruments that
are speculative in nature and do not qualify for hedge
accounting treatment is also recognized
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
immediately in earnings. Proceeds received upon termination of
derivative financial instruments qualifying as fair value hedges
are deferred and amortized into income over the remaining life
of the hedged item using the effective interest rate method.
Litigation
and Insurance Reserves
We estimate our reserves related to litigation and insurance
based on the facts and circumstances specific to the litigation
and insurance claims and our past experience with similar
claims. We maintain actuarially determined accruals in our
consolidated balance sheets to cover self-insurance retentions.
See Note 17 — Commitments and Contingencies
regarding self-insurance accruals. We estimate the range of our
liability related to pending litigation when we believe the
amount and range of loss can be estimated. We record our best
estimate of a loss when the loss is considered probable. When a
liability is probable and there is a range of estimated loss
with no best estimate in the range, we record the minimum
estimated liability related to the lawsuits or claims. As
additional information becomes available, we assess the
potential liability related to our pending litigation and claims
and revise our estimates.
Revenue
Recognition
We recognize revenues and costs on daywork contracts daily as
the work progresses. For certain contracts, we receive lump-sum
payments for the mobilization of rigs and other drilling
equipment. We defer revenue related to mobilization periods and
recognize the revenue over the term of the related drilling
contract. Costs incurred related to a mobilization period for
which a contract is secured are deferred and recognized over the
term of the related drilling contract. Costs incurred to
relocate rigs and other drilling equipment to areas in which a
contract has not been secured are expensed as incurred. We defer
recognition of revenue on amounts received from customers for
prepayment of services until those services are provided.
We recognize revenue for top drives and instrumentation systems
we manufacture when the earnings process is complete. This
generally occurs when products have been shipped, title and risk
of loss have been transferred, collectibility is probable, and
pricing is fixed and determinable.
In connection with the performance of our cementing services, we
recognize product and service revenue when the products are
delivered or services are provided to the customer and
collectibility is reasonably assured. Product sale prices are
determined by published price lists provided to our customers.
We recognize, as operating revenue, proceeds from business
interruption insurance claims in the period that the applicable
proof of loss documentation is received. Proceeds from casualty
insurance settlements in excess of the carrying value of damaged
assets are recognized in losses (gains) on sales and retirements
of long-lived assets and other expense (income), net in the
period that the applicable proof of loss documentation is
received. Proceeds from casualty insurance settlements that are
expected to be less than the carrying value of damaged assets
are recognized at the time the loss is incurred and recorded in
losses (gains) on sales and retirements of long-lived assets and
other expense (income), net.
We recognize reimbursements received for
out-of-pocket
expenses incurred as revenues and account for
out-of-pocket
expenses as direct costs.
We recognize revenue on our interests in oil and gas properties
as production occurs and title passes. We also recognize, as
operating revenues, gains on sales of our interests in oil and
gas properties when title passes and on our earnings associated
with production contracts when realized. We apply the
entitlement method of accounting for natural gas revenue. Under
this method, revenues are recognized based on our revenue
interest of production from our properties in which sales are
disproportionately allocated to owners because of marketing or
other contractual arrangements. Accordingly, revenue is not
recognized for deliveries in excess of our net revenue interest,
while revenue is recognized for any under delivered volumes.
Production imbalances
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
are generally recorded at estimated sales prices of the
anticipated future settlements of the imbalances. Production
volume is monitored to minimize these natural gas imbalances.
Share-Based
Compensation
We record compensation expense for all share-based awards
granted. The amount of compensation expense recognized is based
on the grant-date fair value. Note 6 —
Share-Based Compensation for additional discussion.
Income
Taxes
We are a Bermuda exempt company and are not subject to income
taxes in Bermuda. Consequently, income taxes have been provided
based on the tax laws and rates in effect in the countries in
which our operations are conducted and income is earned. The
income taxes in these jurisdictions vary substantially. Our
effective tax rate for financial statement purposes will
continue to fluctuate from year to year because our operations
are conducted in different taxing jurisdictions.
We recognize increases to our tax reserves for uncertain tax
positions along with interest and penalties as an increase to
other long-term liabilities.
For U.S. and other jurisdictional income tax purposes, we
have net operating and other loss carryforwards that we are
required to assess quarterly for potential valuation allowances.
We consider the sufficiency of existing temporary differences
and expected future earnings levels in determining the amount,
if any, of valuation allowance required against such
carryforwards and against deferred tax assets.
We do not provide for U.S. or global income or withholding
taxes on unremitted earnings of all U.S. and certain
foreign entities, as these earnings are considered permanently
reinvested. Unremitted earnings, represented by tax basis
accumulated earnings and profits, totaled approximately
$7.0 million, $105.0 million and $537.7 million
as of December 31, 2010, 2009 and 2008, respectively. It is
not practicable to estimate the amount of deferred income taxes
associated with these unremitted earnings.
Nabors realizes an income tax benefit associated with certain
awards issued under our stock plans. We recognize the benefits
related to tax deductions up to the amount of the compensation
expense recorded for the award in the consolidated statements of
income (loss). Any excess tax benefit (i.e., tax deduction in
excess of compensation expense) is reflected as an increase in
capital in excess of par. Any shortfall is recorded as a
reduction to capital in excess of par to the extent of our
aggregate accumulated pool of windfall benefits, beyond which
the shortfall would be recognized in the consolidated statements
of income (loss).
Foreign
Currency Translation
For certain of our foreign subsidiaries, such as those in Canada
and Argentina, the local currency is the functional currency,
and therefore translation gains or losses associated with
foreign-denominated monetary accounts are accumulated in a
separate section of the consolidated statements of changes in
equity. For our other international subsidiaries, the
U.S. dollar is the functional currency, and therefore local
currency transaction gains and losses, arising from
remeasurement of payables and receivables denominated in local
currency, are included in our consolidated statements of income
(loss).
Cash
Flows
We treat the redemption price, including accrued original issue
discount, on our convertible debt instruments as a financing
activity for purposes of reporting cash flows in our
consolidated statements of cash flows.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Use of
Estimates
The preparation of financial statements in conformity with GAAP
requires management to make certain estimates and assumptions.
These estimates and assumptions affect the reported amounts of
assets and liabilities, the disclosures of contingent assets and
liabilities at the balance sheet date and the amounts of
revenues and expenses recognized during the reporting period.
Actual results could differ from such estimates. Areas where
critical accounting estimates are made by management include:
| • | financial instruments; | |
| • | depreciation and amortization of property, plant and equipment; | |
| • | impairment of long-lived assets; | |
| • | impairment of goodwill and intangible assets; | |
| • | impairment of oil and gas properties; | |
| • | valuation of oil and gas reserves; | |
| • | income taxes; | |
| • | litigation and self-insurance reserves; | |
| • | fair value of assets acquired and liabilities assumed; and | |
| • | share-based compensation. |
Recent
Accounting Pronouncements
In December 2008, the SEC issued a Final Rule,
“Modernization of Oil and Gas Reporting.” This rule
revises some of the oil and gas reporting disclosures in
Regulation S-K
and
Regulation S-X
under the Securities Act and the Securities Exchange Act of 1934
(the “Exchange Act”), as well as Industry Guide 2.
Effective December 31, 2009, the FASB issued revised
guidance that substantially aligned the oil and gas accounting
disclosures with the SEC’s Final Rule. The amendments are
designed to modernize and update oil and gas disclosure
requirements to align them with current practices and changes in
technology. Additionally, this new accounting standard requires
that entities use
12-month
average natural gas and oil prices when calculating the
quantities of proved reserves and performing the full-cost
ceiling test calculation. The new standard also clarified that
an entity’s equity-method investments must be considered in
determining whether it has significant oil and gas activities.
The disclosure requirements are effective for registration
statements filed on or after January 1, 2010 and for annual
financial statements filed on or after December 31, 2009.
The FASB provided a one-year deferral of the disclosure
requirements if an entity became subject to the requirements
because of a change to the definition of significant oil and gas
activities. When operating results from our wholly owned oil and
gas activities are considered with operating results from our
unconsolidated oil and gas joint ventures, which we account for
under the equity method of accounting, we have significant oil
and gas activities under the new definition. Our oil and gas
disclosures are provided in Note 24 —
Supplementary Information on Oil and Gas Exploration and
Production Activities.
Effective January 1, 2010, we adopted the revised
provisions relating to consolidation of variable interest
entities within the Consolidations Topic of the ASC. The revised
provisions replaced the quantitative approach to identify a
variable interest entity with a qualitative approach that
focuses on an entity’s control and ability to direct the
variable interest entity’s activities. The application of
these provisions did not have a material impact on our
consolidated financial statements.
The FASB issued new guidance relating to revenue recognition for
contractual arrangements with multiple revenue-generating
activities. The ASC Topic for revenue recognition includes
identification of a unit of
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
accounting and how arrangement consideration should be allocated
to separate the units of accounting, when applicable. The new
guidance, including expanded disclosures, will apply to us for
contracts entered into after June 15, 2010. We are
evaluating the impact this guidance may have on future
contracts. Historically, we have not entered into contractual
agreements with multiple revenue-generating activities.
| Note 3 | Impairments and Other Charges |
The following table provides the components of impairments and
other charges recorded during the years ended December 31,
2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Impairment of oil and gas-related assets
|
$ | 192,179 | $ | 197,744 | $ | 21,537 | ||||||
|
Impairment of long-lived assets
|
58,045 | 64,229 | — | |||||||||
|
Goodwill impairments
|
10,707 | 14,689 | 150,008 | |||||||||
|
Impairment of other intangible assets
|
— | — | 4,578 | |||||||||
|
Other-than-temporary
impairment on equity security
|
— | 18,665 | — | |||||||||
|
Other-than-temporary
impairment on debt security
|
— | 40,300 | — | |||||||||
|
Less
other-than-temporary
impairment recognized in accumulated other comprehensive income
(loss)
|
— | (4,651 | ) | — | ||||||||
|
Credit-related impairment on investment
|
— | 35,649 | — | |||||||||
|
Impairments and other charges
|
$ | 260,931 | $ | 330,976 | $ | 176,123 | ||||||
Impairments
of Oil and Gas Assets
In 2010, we recognized impairments of $192.2 million
related to our wholly owned oil and gas assets. Of this
total, $137.8 million represents writedowns to the carrying
value of some acreage in the United States, which we do not have
future plans to develop due to the sustained low natural gas
prices, and certain exploratory wells in Colombia, which we have
determined will be uneconomical to develop in the foreseeable
future.
The remaining $54.3 million relates to an impairment of a
financing receivable as a result of the continued commodity
price deterioration in the Barnett Shale area of north central
Texas. We determined that this impairment was necessary using
estimates and assumptions based on estimated cash flows for
proved and probable reserves and current natural gas prices. We
believe the estimates used provide a reasonable estimate of
current fair value. We determined that this represented a
Level 3 fair value measurement. As of December 31,
2010, the carrying value of this oil and gas financing
receivable, which is included in long-term investments, has been
reduced to $20.1 million. A further protraction or
continued period of lower commodity prices could result in
recognition of future impairment charges.
In 2009, we recorded impairments totaling $197.7 million to
some of our wholly owned oil and gas assets. We recognized an
impairment of $149.1 million to a financing receivable as a
result of commodity price deterioration and the lower price
environment last longer than expected. The prolonged period of
lower prices significantly reduced demand for future gas
production and development in the Barnett Shale area of north
central Texas and influenced our decision not to expend capital
to develop on some of the undeveloped acreage. The impairment,
which represented a Level 3 fair value measurement, was
determined using discounted cash flow models involving
assumptions based on estimated cash flows for proved and
probable reserves, undeveloped acreage value, and current and
expected natural gas prices. Additionally, our annual
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
impairment tests on our U.S. wholly owned oil and gas
properties resulted in impairment charges of $48.6 million
to writedown the carrying value of some acreage that we do not
have future plans to develop.
In 2008, our annual impairment tests on our U.S. wholly
owned oil and gas properties resulted in impairment charges of
$21.5 million primarily due to the significant decline in
oil and natural gas prices at the end of 2008. Additional
discussion of our policy pertaining to the calculation of our
annual impairment tests is set forth in “Oil and Gas
Properties” in Note 2 — Summary of
Significant Accounting Policies.
Impairments
of Long-Lived Assets
In 2010, we recognized impairments of $58.0 million in
multiple operating segments. These impairments included
$23.2 million related to the retirement of certain rig
components, comprised of engines, top-drive units, building
modules and other equipment that has become obsolete or
inoperable in each of these operating segments in our
U.S. Lower 48 Land Drilling, U.S. Land Well-servicing
and U.S. Offshore Contract Drilling segment. The impairment
charges were determined to be necessary as a result of the
continued lower commodity price environment and its related
impact on drilling and well-servicing activity and our dayrates.
A prolonged period of legislative uncertainty in our U.S.
Offshore operations, or continued period of and lower natural
gas and oil prices and its potential impact on our utilization
and dayrates could result in the recognition of future
impairment charges to additional assets if future cash flow
estimates, based upon information then available to management,
indicate that the carrying value of those assets may not be
recoverable.
The remaining $34.8 million in impairment charges recorded
during 2010 include $27.3 million related to the impairment
of some
jack-up
rigs
in our U.S. Offshore operating segment and
$7.5 million to our aircraft and some drilling equipment in
Nabors Blue Sky Ltd. These impairment charges stemmed from our
annual impairment tests on long-lived assets, which determined
that the sum of the estimated future cash flows, on an
undiscounted basis, was less than the carrying amount of these
assets. The estimated fair values of these assets were
calculated using discounted cash flow models involving
assumptions based on our utilization of the assets, revenues as
well as direct costs, capital expenditures and working capital
requirements. The impairment charge relating to our
U.S. Offshore segment was deemed necessary due to the
economic conditions for drilling in the Gulf of Mexico, as
discussed below. The impairment charge relating to Nabors Blue
Sky Ltd. was deemed necessary due to the continued duration of
the downturn in the oil and gas industry in Canada, which has
resulted in diminished demand for the remote access services
provided by this subsidiary’s aircraft fleet.
In 2009, we recognized impairments of $64.2 million related
to retirements of certain assets in our U.S. Offshore,
Alaska, Canada and International Contract Drilling segments,
which reduced their aggregate carrying value to their estimated
aggregate salvage value. The retirements included inactive
workover
jack-up
rigs
in our U.S. Offshore and International operations, the
structural frames of some incomplete coiled tubing rigs in our
Canada operations and miscellaneous rig components in our Alaska
operations. The impairment charges resulted from the continued
deterioration and longer than expected downturn in the demand
for oil and gas drilling activities.
Goodwill
Impairments
In 2010, we recognized an impairment of approximately
$10.7 million relating to our goodwill balance of our
U.S. Offshore operating segment. The impairment charge
stemmed from our annual impairment test on goodwill, which
compared the estimated fair value of each of our reporting units
to its carrying value. The estimated fair value of our
U.S. Offshore segment was determined using discounted cash
flow models involving assumptions based on our utilization of
rigs and revenues as well as direct costs, general and
administrative costs, depreciation, applicable income taxes,
capital expenditures and working capital requirements. We
determined that the fair value estimated for purposes of this
test represented a Level 3 fair value measurement. The
impairment charge was deemed necessary due to the uncertainty of
utilization of some of
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
our rigs as a result of changes in our customers’ plans for
future drilling operations in the Gulf of Mexico. Many of our
customers have suspended drilling operations in the Gulf of
Mexico, largely as a result of their inability to obtain
government permits. Although the U.S. deepwater drilling
moratorium has been lifted, it is uncertain whether our
customers’ ability to obtain government permits will
improve in the near term. A significantly prolonged period of
lower oil and natural gas prices or changes in laws and
regulations could adversely affect the demand for and prices of
our services, which could result in future goodwill impairment
charges for other reporting units due to the potential impact on
our estimate of our future operating results. See
Note 2 — Summary of Significant Accounting
Policies (included under the caption “Goodwill”) for
amounts of goodwill related to each of our reporting units.
In 2009, we impaired the remaining goodwill balance of
$14.7 million of Nabors Blue Sky Ltd., one of our Canadian
subsidiaries who provides access to remote drilling sites by
helicopters and fixed-wing aircraft. The impairment charges
resulted from our annual impairment tests on goodwill which
compared the estimated fair value of each of our reporting units
to its carrying value. The estimated fair value of these
business units was determined using discounted cash flow models
involving assumptions based on our utilization of rigs or
aircraft, revenues and earnings from affiliates, as well as
direct costs, general and administrative costs, depreciation,
applicable income taxes, capital expenditures and working
capital requirements. We determined that the fair value
estimated for purposes of this test represented a Level 3
fair value measurement. The impairment charges were deemed
necessary due to the continued downturn in the oil and gas
industry in Canada and the lack of certainty regarding eventual
recovery in the value of these operations. This downturn led to
reduced capital spending by some of our customers and diminished
demand for our drilling services and for immediate access to
remote drilling sites.
In 2008, we impaired the entire goodwill balance of
$145.4 million of our Canada Well-servicing and Drilling
operating segment and recorded an impairment of
$4.6 million to Nabors Blue Sky Ltd. This impairment was
also deemed necessary due to the continued downturn in the oil
and gas industry in Canada and the lack of certainty regarding
eventual recovery in the value of these operations. This
downturn led to reduced capital spending by some of our
customers and diminished demand for our drilling services and
for immediate access to remote drilling sites.
Other
than Temporary Impairments on Debt and Equity
Securities
In 2009, we recorded
other-than-temporary
impairments to our
available-for-sale
securities totaling $54.3 million. Of this,
$35.6 million was related to an investment in a corporate
bond that was downgraded to non-investment grade level by
Standard and Poor’s and Moody’s Investors Service
during the year. Our determination that the impairment was
other-than-temporary was based on a variety of factors,
including the length of time and extent to which the market
value had been less than cost, the financial condition of the
issuer of the security, and the credit ratings and recent
reorganization of the issuer.
The remaining $18.7 million related to an equity security
of a public company whose operations are driven in large measure
by the price of oil and in which we invested approximately
$46 million during the second and third quarters of 2008.
During late 2008, demand for oil and gas began to diminish
significantly as part of the general deterioration of the global
economic environment, causing a broad decline in value of nearly
all oil and gas-related equity securities. Because the trading
price per share of this security remained below our cost basis
for an extended period of time, we determined the investment was
other than temporarily impaired and it was appropriate to write
down its carrying value to its estimated fair value.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 4 | Cash and Cash Equivalents and Investments |
Our cash and cash equivalents, short-term and long-term
investments and other receivables consisted of the following:
|
December 31,
|
December 31,
|
|||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Cash and cash equivalents
|
$ | 641,702 | $ | 927,815 | ||||
|
Short-term investments:
|
||||||||
|
Trading equity securities
|
19,630 | 24,014 | ||||||
|
Available-for-sale
equity securities
|
79,698 | 93,651 | ||||||
|
Available-for-sale
debt securities
|
60,160 | 45,371 | ||||||
|
Total short-term investments
|
159,488 | 163,036 | ||||||
|
Long-term investments and other receivables
|
40,300 | 100,882 | ||||||
|
Total
|
$ | 841,490 | $ | 1,191,733 | ||||
Certain information related to our cash and cash equivalents and
short-term investments follows:
| December 31, | ||||||||||||||||||||||||
| 2010 | 2009 | |||||||||||||||||||||||
|
Gross
|
Gross
|
Gross
|
Gross
|
|||||||||||||||||||||
|
Unrealized
|
Unrealized
|
Unrealized
|
Unrealized
|
|||||||||||||||||||||
|
Fair
|
Holding
|
Holding
|
Fair
|
Holding
|
Holding
|
|||||||||||||||||||
| Value | Gains | Losses | Value | Gains | Losses | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 641,702 | $ | — | $ | — | $ | 927,815 | $ | — | $ | — | ||||||||||||
|
Short-term investments:
|
||||||||||||||||||||||||
|
Trading equity securities
|
19,630 | 13,906 | — | 24,014 | 18,290 | — | ||||||||||||||||||
|
Available-for-sale
equity securities
|
79,698 | 38,176 | (2,274 | ) | 93,651 | 50,211 | (357 | ) | ||||||||||||||||
|
Available-for-sale
debt securities:
|
||||||||||||||||||||||||
|
Commercial paper and CDs
|
1,275 | — | — | 1,284 | — | — | ||||||||||||||||||
|
Corporate debt securities
|
52,022 | 15,274 | (18 | ) | 33,852 | 3,162 | ||||||||||||||||||
|
Mortgage-backed debt securities
|
372 | 16 | — | 861 | 23 | (20 | ) | |||||||||||||||||
|
Mortgage-CMO debt securities
|
3,015 | 21 | (6 | ) | 5,411 | 71 | (182 | ) | ||||||||||||||||
|
Asset-backed debt securities
|
3,476 | — | (268 | ) | 3,963 | — | (803 | ) | ||||||||||||||||
|
Total
available-for-sale
debt securities
|
60,160 | 15,311 | (292 | ) | 45,371 | 3,256 | (1,005 | ) | ||||||||||||||||
|
Total
available-for-sale
securities
|
139,858 | 53,487 | (2,566 | ) | 139,022 | 53,467 | (1,362 | ) | ||||||||||||||||
|
Total short-term investments
|
159,488 | 67,393 | (2,566 | ) | 163,036 | 71,757 | (1,362 | ) | ||||||||||||||||
|
Total cash, cash equivalents and short-term investments
|
$ | 801,190 | $ | 67,393 | $ | (2,566 | ) | $ | 1,090,851 | $ | 71,757 | $ | (1,362 | ) | ||||||||||
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NOTES TO
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STATEMENTS — (Continued)
Certain information related to the gross unrealized losses of
our cash and cash equivalents and short-term investments follows:
| As of December 31, 2010 | ||||||||||||||||
| Less than 12 Months | More than 12 Months | |||||||||||||||
|
Gross
|
Gross
|
|||||||||||||||
|
Unrealized
|
Unrealized
|
|||||||||||||||
| Fair Value | Loss | Fair Value | Loss | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Available-for-sale
equity securities
|
$ | 24,924 | $ | 2,072 | $ | 882 | $ | 202 | ||||||||
|
Available-for-sale
debt securities: (1)
|
||||||||||||||||
|
Corporate debt securities
|
19,747 | 18 | — | — | ||||||||||||
|
Mortgage-CMO debt securities
|
— | — | 149 | 6 | ||||||||||||
|
Asset-backed debt securities
|
— | — | 3,464 | 268 | ||||||||||||
|
Total
available-for-sale
debt securities
|
19,747 | 18 | 3,613 | 274 | ||||||||||||
|
Total
|
$ | 44,671 | $ | 2,090 | $ | 4,495 | $ | 476 | ||||||||
| (1) | Our unrealized losses on available-for-sale debt securities held for more than one year are comprised of various types of securities. Each of these securities have a rating ranging from “A” to “AAA” from Standard & Poor’s and ranging from “A2” to “Aaa” from Moody’s Investors Service and is considered of high credit quality. In each case, we do not intend to sell these investments, and it is less likely than not that we will be required to sell them to satisfy our own cash flow and working capital requirements. We believe that we will be able to collect all amounts due according to the contractual terms of each investment and, therefore, do not consider the decline in value of these investments to be other-than-temporary at December 31, 2010. |
The estimated fair values of our corporate, mortgage-backed,
mortgage-CMO and asset-backed debt securities at
December 31, 2010, classified by time to contractual
maturity, are shown below. Expected maturities differ from
contractual maturities because the issuers of the securities may
have the right to repay obligations without prepayment penalties
and we may elect to sell the securities prior to the contractual
maturity date.
|
Estimated
|
||||
|
Fair Value
|
||||
| December 31, 2010 | ||||
| (In thousands) | ||||
|
Debt securities:
|
||||
|
Due in one year or less
|
$ | 1,279 | ||
|
Due after one year through five years
|
— | |||
|
Due in more than five years
|
58,881 | |||
|
Total debt securities
|
$ | 60,160 | ||
Certain information regarding our debt and equity securities is
presented below:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Available-for-sale:
|
||||||||||||
|
Proceeds from sales and maturities
|
$ | 13,062 | $ | 23,411 | $ | 202,382 | ||||||
|
Realized gains (losses), net
|
(103 | ) | (54,314 | )(1) | 180 | |||||||
| (1) | Includes other-than-temporary impairments of $18.7 million related to an equity security and a $35.6 million credit-related impairment to a corporate debt security. |
83
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 5 | Fair Value Measurements |
As defined in the ASC, fair value is the price that would be
received upon sale of an asset or paid upon transfer of a
liability in an orderly transaction between market participants
at the measurement date (exit price). We utilize market data or
assumptions that market participants would use in pricing the
asset or liability, including assumptions about risk and the
risks inherent in the inputs to the valuation technique. These
inputs can be readily observable, market-corroborated, or
generally unobservable. We primarily apply the market approach
for recurring fair value measurements and endeavor to utilize
the best information available. Accordingly, we employ valuation
techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. The use of unobservable
inputs is intended to allow for fair value determinations in
situations where there is little, if any, market activity for
the asset or liability at the measurement date. We are able to
classify fair value balances utilizing a fair value hierarchy
based on the observability of those inputs. Under the fair value
hierarchy
| • | Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market; | |
| • | Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and | |
| • | Level 3 measurements include those that are unobservable and of a subjective measure. |
The following table sets forth, by level within the fair value
hierarchy, our financial assets and liabilities that are
accounted for at fair value on a recurring basis as of
December 31, 2010. Our financial assets and liabilities are
classified in their entirety based on the lowest level of input
that is significant to the fair value measurement.
Recurring
Fair Value Measurements
| Fair Value as of December 31, 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Assets:
|
||||||||||||||||
|
Short-term investments:
|
||||||||||||||||
|
Available-for-sale
equity securities — energy industry
|
$ | 79,698 | $ | — | $ | — | $ | 79,698 | ||||||||
|
Available-for-sale
debt securities
|
||||||||||||||||
|
Commercial paper and CDs
|
1,275 | — | — | 1,275 | ||||||||||||
|
Corporate debt securities
|
— | 52,022 | — | 52,022 | ||||||||||||
|
Mortgage-backed debt securities
|
— | 372 | — | 372 | ||||||||||||
|
Mortgage-CMO debt securities
|
— | 3,015 | — | 3,015 | ||||||||||||
|
Asset-backed debt securities
|
3,476 | — | — | 3,476 | ||||||||||||
|
Trading securities — energy industry
|
19,630 | — | — | 19,630 | ||||||||||||
|
Total short-term investments
|
$ | 104,079 | $ | 55,409 | $ | — | $ | 159,488 | ||||||||
|
Liabilities:
|
||||||||||||||||
|
Derivative contract
|
$ | — | $ | 3,440 | $ | — | $ | 3,440 | ||||||||
84
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Nonrecurring
Fair Value Measurements
Fair value measurements were applied with respect to our
nonfinancial assets and liabilities measured on a nonrecurring
basis, which consists primarily of goodwill, oil and gas
financing receivables, intangible assets and other long-lived
assets, assets acquired and liabilities assumed in a business
combination, and asset retirement obligations. Refer to
Note 3 — Impairments and Other Charges for
additional discussion.
Fair
Value of Financial Instruments
The fair value of our financial instruments has been estimated
in accordance with GAAP. The fair value of our fixed rate
long-term debt is estimated based on quoted market prices or
prices quoted from third-party financial institutions. The fair
value of our subsidiary preferred stock was estimated based on
the allocation of the purchase price. The carrying and fair
values of these liabilities were as follows:
| December 31, | ||||||||||||||||
| 2010 | 2009 | |||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||
| (In thousands) | ||||||||||||||||
|
0.94% senior exchangeable notes due May 2011
|
$ | 1,378,178 | $ | 1,403,315 | $ | 1,576,480 | $ | 1,668,368 | ||||||||
|
6.15% senior notes due February 2018
|
966,276 | 1,041,008 | 965,066 | 992,531 | ||||||||||||
|
9.25% senior notes due January 2019
|
1,125,000 | 1,393,943 | 1,125,000 | 1,403,719 | ||||||||||||
|
5.00% senior notes due September 2020
|
697,037 | 678,335 | — | — | ||||||||||||
|
5.375% senior notes due August 2012(1)
|
273,977 | 291,500 | 273,350 | 289,072 | ||||||||||||
|
Subsidiary preferred stock
|
69,188 | 68,625 | — | — | ||||||||||||
|
Other
|
2,676 | 2,676 | 872 | 872 | ||||||||||||
| $ | 4,512,332 | $ | 4,879,402 | $ | 3,940,768 | $ | 4,354,562 | |||||||||
| (1) | Includes $.7 million and $1.1 million as of December 31, 2010 and 2009, respectively, related to the unamortized loss on the interest rate swap that was unwound during the fourth quarter of 2005. |
The fair values of our cash equivalents, trade receivables and
trade payables approximate their carrying values due to the
short-term nature of these instruments.
As of December 31, 2010, our short-term investments were
carried at fair market value and included $139.9 million
and $19.6 million in securities classified as
available-for-sale
and trading, respectively. As of December 31, 2009, our
short-term investments were carried at fair market value and
included $139.0 million and $24.0 million in
securities classified as
available-for-sale
and trading, respectively. The carrying values of our long-term
investments that are accounted for using the equity method of
accounting approximate fair value. The fair value of these
long-term investments totaled $7.4 million and
$8.3 million as of December 31, 2010 and 2009,
respectively. The carrying value of our oil and gas financing
receivables included in long-term investments approximate fair
value. The carrying value of our oil and gas financing
receivables totaled $32.9 million and $92.5 million as
of December 31, 2010 and 2009, respectively. Income and
gains associated with our oil and gas financing receivables are
recognized as operating revenues.
| Note 6 | Share-Based Compensation |
Total share-based compensation expense, which includes both
stock options and restricted stock, totaled $13.7 million,
$106.7 million and $45.4 million for the years ended
December 31, 2010, 2009 and 2008,
85
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
respectively. Compensation expense related to awards of
restricted stock totaled $10.5 million, $88.9 million
and $44.6 million for the years ended December 31,
2010, 2009 and 2008, respectively, and is included in direct
costs and general and administrative expenses in our
consolidated statements of income (loss). Share-based
compensation expense has been allocated to our various operating
segments. See Note 22 — Segment Information.
Total share-based compensation expense for 2009 includes the
recognition of $72.1 million of compensation expense
related to previously granted restricted stock and option awards
held by Messrs. Isenberg and Petrello that was unrecognized
as of April 1, 2009. The recognition of this expense
resulted from provisions of their respective new employment
agreements which effectively eliminated the risk of forfeiture
of such awards. See Note 17 — Commitments and
Contingencies for additional information.
The cash flows resulting from tax deductions in excess of the
compensation cost recognized for share-based awards (excess tax
benefits) are classified as financing cash flows. The actual tax
benefit realized from share-based awards during the years ended
December 31, 2010, 2009 and 2008 was $.1 million,
$.3 million and $7.6 million, respectively.
Stock
Option Plans
As of December 31, 2010, we had several stock plans under
which options to purchase our common shares could be granted to
key officers, directors and managerial employees of Nabors and
its subsidiaries. Options granted under the plans generally are
at prices equal to the fair market value of the shares on the
date of the grant. Options granted under the plans generally are
exercisable in varying cumulative periodic installments after
one year. In the case of certain key executives, options granted
under the plans are subject to accelerated vesting related to
targeted common share prices, or may vest immediately on the
grant date. Options granted under the plans cannot be exercised
more than ten years from the date of grant. Options to purchase
17.3 million and 12.0 million Nabors common shares
remained available for grant as of December 31, 2010 and
2009, respectively. Of the common shares available for grant as
of December 31, 2010, approximately 17.3 million of
these shares are also available for issuance in the form of
restricted shares.
The fair value of each option award is estimated on the date of
grant using the Black-Scholes option-pricing model which uses
assumptions for the risk-free interest rate, volatility,
dividend yield and the expected term of the options. The
risk-free interest rate is based on the U.S. Treasury yield
curve in effect at the time of grant for a period equal to the
expected term of the option. Expected volatilities are based on
implied volatilities from traded options on Nabors’ common
shares, historical volatility of Nabors’ common shares, and
other factors. We do not assume any dividend yield, since we do
not pay dividends. We use historical data to estimate the
expected term of the options and employee terminations within
the option-pricing model; separate groups of employees that have
similar historical exercise behavior are considered separately
for valuation purposes. The expected term of the options
represents the period of time that the options granted are
expected to be outstanding.
We also consider an estimated forfeiture rate for these option
awards, and we recognize compensation cost only for those shares
that are expected to vest, on a straight-line basis over the
requisite service period of the award, which is generally the
vesting term of three to five years. The forfeiture rate is
based on historical experience. Estimated forfeitures have been
adjusted to reflect actual forfeitures during 2010.
86
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Stock option transactions under our various stock-based employee
compensation plans are presented below:
|
Weighted-
|
||||||||||||||||
|
Average
|
||||||||||||||||
|
Remaining
|
Aggregate
|
|||||||||||||||
|
Weighted-Average
|
Contractual
|
Intrinsic
|
||||||||||||||
| Options | Shares | Exercise Price | Term | Value | ||||||||||||
| (In thousands, except exercise price) | ||||||||||||||||
|
Options outstanding as of December 31, 2009
|
33,416 | $ | 18.90 | |||||||||||||
|
Granted
|
32 | 19.28 | ||||||||||||||
|
Exercised
|
(714 | ) | 13.28 | |||||||||||||
|
Surrendered(1)
|
(3,375 | ) | 22.44 | |||||||||||||
|
Forfeited
|
(427 | ) | 12.35 | |||||||||||||
|
Options outstanding as of December 31, 2010
|
28,932 | $ | 18.73 | 4.42 years | $ | 199,164 | ||||||||||
|
Options exercisable as of December 31, 2010
|
24,941 | $ | 20.19 | 3.82 years | $ | 143,939 | ||||||||||
| (1) | Represents unexercised vested stock options, which were surrendered by key officers and directors, to satisfy the option exercise price and related income taxes. See related discussion at Note 13 — Common Shares. |
Of the options outstanding, 24.9 million, 27.2 million
and 25.9 million were exercisable at weighted-average
exercise prices of $20.19, $21.04 and $21.99, as of
December 31, 2010, 2009 and 2008, respectively.
During the years ended December 31, 2010 and 2009,
respectively, we awarded options vesting over periods up to four
years to purchase 32,115 and 10,015,883 of our common shares to
our employees, executive officers and directors. There were no
options granted during the year ended December 31, 2008.
During February 2009, this included options to purchase
3,000,000 and 1,698,427 shares, with grant date fair values
of $8.8 million and $5.0 million, granted to
Messrs. Isenberg and Petrello, respectively, and in
September 2009, an option to purchase 1,726 shares, with a
grant date fair value of $.01 million, to Mr. Petrello
in lieu of certain portions of their cash compensation.
The fair value of stock options granted during 2010 and 2009 was
calculated using the Black-Scholes option pricing model and the
following weighted-average assumptions:
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
|
Weighted average fair value of options granted:
|
$ | 6.62 | $ | 2.85 | ||||
|
Weighted average risk free interest rate:
|
1.49 | % | 1.75 | % | ||||
|
Dividend yield:
|
0 | % | 0 | % | ||||
|
Volatility:(1)
|
41.44 | % | 34.78 | % | ||||
|
Expected life:
|
4.0 years | 4.0 years | ||||||
| (1) | Expected volatilities are based on implied volatilities from publicly traded options to purchase Nabors’ common shares, historical volatility of Nabors’ common shares and other factors. |
87
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A summary of our unvested stock options as of December 31,
2010, and the changes during the year then ended is presented
below:
|
Weighted-Average
|
||||||||
|
Grant-Date Fair
|
||||||||
| Unvested Stock Options | Outstanding | Value | ||||||
| (In thousands, except fair values) | ||||||||
|
Unvested as of December 31, 2009
|
6,174 | $ | 2.82 | |||||
|
Granted
|
32 | 6.62 | ||||||
|
Vested
|
(1,929 | ) | 2.91 | |||||
|
Forfeited
|
(336 | ) | 2.73 | |||||
|
Unvested as of December 31, 2010
|
3,941 | $ | 2.81 | |||||
The total intrinsic value of options exercised during the years
ended December 31, 2010, 2009 and 2008 was
$6.9 million, $19.7 million and $43.6 million,
respectively. The total fair value of options that vested during
the years ended December 31, 2010, 2009 and 2008 was
$5.6 million, $10.8 million and $4.3 million,
respectively.
As of December 31, 2010, there was $6.2 million of
total future compensation cost related to unvested options which
are expected to vest. That cost is expected to be recognized
over a weighted-average period of approximately one year.
Restricted
Stock and Restricted Stock Units
Our stock plans allow grants of restricted stock. Restricted
stock is issued on the grant date, but cannot be sold or
transferred. Restricted stock vests in varying periodic
installments ranging from three to five years.
A summary of our restricted stock as of December 31, 2010,
and the changes during the year then ended, is presented below:
|
Weighted-Average
|
||||||||
|
Grant-Date Fair
|
||||||||
| Restricted Stock | Outstanding | Value | ||||||
| (In thousands, except fair values) | ||||||||
|
Unvested as of December 31, 2009
|
3,632 | $ | 20.99 | |||||
|
Granted
|
539 | 22.15 | ||||||
|
Vested
|
(2,172 | ) | 22.68 | |||||
|
Forfeited
|
(54 | ) | 28.10 | |||||
|
Unvested as of December 31, 2010
|
1,945 | $ | 19.23 | |||||
During 2010 and 2009, we awarded 538,496 and 85,000 shares
of restricted stock, respectively, to our employees and
directors. These awards had an aggregate value at their date of
grant of $11.9 million and $1.0 million, respectively,
and were scheduled to vest over a period of up to four years.
The fair value of restricted stock that vested during the years
ended December 31, 2010, 2009 and 2008 was
$26.7 million, $23.9 million and $39.6 million,
respectively.
As of December 31, 2010, there was $15.0 million of
total future compensation cost related to unvested restricted
stock awards which are expected to vest. That cost is expected
to be recognized over a weighted-average period of approximately
one year.
88
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 7 | Acquisitions and Divestitures |
Acquisitions
On September 10, 2010, we completed the Superior Merger,
and we acquired all of the issued and outstanding shares of
Superior’s common stock at a price per share equal to
$22.12, for a cash purchase price of approximately
$681.3 million. The purchase price for Superior was
allocated to the net tangible and intangible assets acquired and
liabilities assumed based on fair value. The excess of the
purchase price over such fair values was recorded as goodwill.
As part of the Superior Merger, we recognized $7.0 million
of acquisition-related transaction costs in losses (gains) on
sales and retirements of long-lived assets and other expense
(income) for the year ended December 31, 2010. The
acquisition-related transaction costs consisted primarily of
investment banking fees and legal and accounting costs. The
Superior Merger enhances our well-servicing, including the
addition of hydraulic fracturing to our services, and workover
capacity work throughout the Appalachian, Mid-Continent, Rocky
Mountain, Southeast and Southwest regions of the United States.
The following table provides the allocation of the purchase
price as of the acquisition date. This allocation was based on
the significant use of estimates and on information that was
available to management at the time these consolidated financial
statements were prepared.
|
Estimated Fair
|
||||
| Value | ||||
| (In thousands) | ||||
|
Consideration paid in cash
|
$ | 681,275 | ||
|
Assets:
|
||||
|
Cash and cash equivalents
|
$ | 1,045 | ||
|
Accounts receivable
|
143,842 | |||
|
Inventory
|
33,963 | |||
|
Other current assets
|
7,612 | |||
|
Property, plant and equipment
|
415,000 | |||
|
Intangible assets
|
131,811 | |||
|
Goodwill
|
334,992 | |||
|
Other long-term assets
|
14,726 | |||
|
Total assets
|
1,082,991 | |||
|
Liabilities:
|
||||
|
Current liabilities
|
$ | 78,277 | ||
|
Deferred income taxes
|
119,201 | |||
|
Long-term debt
|
124,792 | |||
|
Other long-term liabilities
|
10,258 | |||
|
Total liabilities
|
332,528 | |||
|
Preferred stock
|
69,188 | |||
|
Net assets acquired
|
$ | 681,275 | ||
Intangible
assets
We identified other intangible assets associated with fracturing
and fluid logistics services, including trade name, technology,
employment contracts and non-compete agreements and customer
relationships. The amortization of the intangible assets is
calculated on a straight-line basis, which estimates the
consumption of
89
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
economic benefits. The following table summarizes the intangible
assets recognized at the acquisition date, the monthly
amortization expense as well as their estimated useful lives:
|
Estimated Fair
|
Monthly
|
Estimated
|
||||||||||
| Value | Amortization | Useful Life | ||||||||||
| (In thousands) | ||||||||||||
|
Superior trade name
|
$ | 88,767 | $ | 740 | 10 years | |||||||
|
Technology
|
5,294 | 88 | 5 years | |||||||||
|
Employment contracts and non-compete agreements
|
675 | 33 | 1-3 years | |||||||||
|
Customer relationships
|
37,075 | 308 | 10 years | |||||||||
|
Total identifiable intangible assets
|
$ | 131,811 | $ | 1,169 | ||||||||
Goodwill
Goodwill of $335.0 million arising from the Superior Merger
consists largely of the expected synergies and economies of
scale from combining the operations of Nabors and Superior. We
have allocated the goodwill to our Pressure Pumping operating
segment. See Note 2 — Summary of Significant
Account Policies for additional information.
Long-term debt included a secured revolving credit facility,
which had approximately $44.8 million outstanding at the
acquisition date. As of December 31, 2010, all amounts
outstanding under the credit facility had been repaid. See
Note 11 — Debt for additional information.
Long-term debt also included second lien notes, which had an
aggregate principal amount of $80 million outstanding at
the acquisition date. We exercised our right to redeem these
notes and, on October 25, 2010, paid $80.4 million to
repurchase all outstanding notes and related accrued interest.
Pro
Forma Impact of the Superior Merger
The following unaudited supplemental pro forma results present
consolidated information as if the Superior Merger had been
completed as of January 1, 2009. The pro forma results
include: (i) the amortization associated with an estimate
of the acquired intangible assets, (ii) interest expense
associated with debt used to fund the acquisition,
(iii) the impact of certain fair value adjustments,
including additional depreciation expense for adjustments to
property, plant and equipment and reduction to interest expense
for adjustments to debt, and (iv) costs directly related to
acquiring Superior. Accordingly, the pro forma results should
not be considered indicative of the results that would have
occurred if the acquisition and related borrowings had been
consummated as of January 1, 2009; nor are they indicative
of future results.
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands, except per share amounts) | ||||||||
|
Total revenues and other income
|
$ | 4,936,407 | $ | 3,954,445 | ||||
|
Net income (loss) attributable to Nabors
|
$ | 168,213 | $ | (203,719 | ) | |||
Superior’s operating results for the period
September 10, 2010 through December 31, 2010 are
reflected in our operating segment titled Pressure Pumping in
our segment footnote. See Note 22 — Segment
Information for additional discussion.
On December 31, 2010, we purchased the business of Energy
Contractors for a total cash purchase price of
$53.4 million. The assets were comprised of vehicles and
rig equipment and have been included in our
90
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
U.S. Well-servicing operating segment. The purchase price
was allocated to the net tangible and intangible assets acquired
based on their preliminary fair value estimates as of
December 31, 2010. The excess of the purchase price over
the fair values of the assets acquired was recorded as goodwill
in the amount of $5.0 million.
Divestitures
From time to time, we may sell a subsidiary or group of assets
outside of our core markets or business if it is economically
advantageous for us to do so. During 2010, we began actively
marketing some of our oil and gas assets. See
Note 21 — Discontinued Operations for additional
discussion.
| Note 8 | Property, Plant and Equipment |
The major components of our property, plant and equipment are as
follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Land
|
$ | 12,087 | $ | 9,251 | ||||
|
Buildings
|
122,635 | 93,874 | ||||||
|
Drilling, workover and well-servicing rigs, and related equipment
|
10,632,968 | 9,515,677 | ||||||
|
Marine transportation and supply vessels
|
13,663 | 13,663 | ||||||
|
Oilfield hauling and mobile equipment
|
551,892 | 533,518 | ||||||
|
Other machinery and equipment
|
143,976 | 202,389 | ||||||
|
Oil and gas properties
|
664,289 | 752,809 | ||||||
|
Construction in process(1)
|
349,455 | (2) | 314,493 | |||||
| 12,490,965 | 11,435,674 | |||||||
|
Less: accumulated depreciation and amortization
|
(4,182,122 | ) | (3,453,193 | ) | ||||
|
accumulated depletion on oil and gas properties
|
(493,424 | ) | (336,431 | ) | ||||
| $ | 7,815,419 | $ | 7,646,050 | |||||
| (1) | Relates to amounts capitalized for new or substantially new drilling, workover and well-servicing rigs that were under construction and had not yet been placed in service as of December 31, 2010 or 2009. | |
| (2) | Includes suspended wells that have capitalized costs for more than one year as of December 31, 2010. Suspended wells include the following: |
| • | On the north slope of Alaska, three wells, including two drilled in 2007 and one drilled in 2008, were suspended with total capitalized costs of $13.7 million and $5.9 million, respectively for each year. Further drilling is needed over the area to determine if the discovery holds sufficient quantities of reserves to justify future investment of infrastructure. During 2010, we drilled two wells in this area, and another well is planned to spud in March 2011. | |
| • | In the Cotton Valley in Bossier County, Louisiana, five wells were suspended in the Sentell field. Total capitalized costs of $2.6 million and $3.6 million relate to three wells drilled in 2008 and two wells drilled in 2009, respectively for each year. The wells are suspended pending negotiation of a pipeline right-of-way. | |
| • | In the Fayetteville Shale in Conway County, Arkansas, two wells, drilled in 2008 with total capitalized costs of $11.2 million, are suspended pending the outcome of drilling in the area by other operators. |
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Industries Ltd. and Subsidiaries
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| • | In Reeves County, Texas, five wells, drilled in 2009, have total capitalized costs of $3.0 million. Of the five, one well is producing and the remaining four are suspended and wait on hydraulic fracturing. | |
| • | In the Middle Magdalena basin of Colombia, two wells were suspended. The Guariquies #1 and Morpho #1 wells were drilled in 2005 and 2009 with total capitalized costs of $1.5 million and $4.3 million, respectively. The Guariquies #1 is expected to be turned to production in May 2011, and the Morpho #1 was turned to production in January 2011. An offset to Morpho #1 was drilled in 2010. | |
| • | In the Horn River Basin of British Columbia, Canada, one well was drilled in 2009 and was waiting on hydraulic fracturing as of December 31, 2010. Total capitalized costs were $12.5 million. This well is part of the Canadian oil and gas assets that are classified as held-for-sale at December 31, 2010. When completed, this well will be produced into the wholly owned compression and pipeline facility along with two other wells that were drilled in 2009 that are currently producing. |
Assets held under capital leases totaled $.9 million as of
December 31, 2010, and are included in our property, plant
and equipment within the oilfield hauling and mobile equipment
asset component. Amortization of assets recorded under capital
leases is reported in depreciation and amortization expense.
Repair and maintenance expense included in direct costs in our
consolidated statements of income (loss) totaled
$390.2 million, $282.1 million and $476.6 million
for the years ended December 31, 2010, 2009 and 2008,
respectively.
Interest costs of $12.4 million, $29.9 million and
$29.8 million were capitalized during the years ended
December 31, 2010, 2009 and 2008, respectively.
| Note 9 | Investments in Unconsolidated Affiliates |
Our principal investments in unconsolidated affiliates accounted
for using the equity method include a construction and logistics
operation in Alaska (50% ownership), drilling and workover
operations located in Saudi Arabia (51% ownership) and oil and
gas exploration, development and production joint ventures in
the United States and Colombia (49.7% ownership) and Canada (50%
ownership). These unconsolidated affiliates are integral to our
operations in those locations. During 2008, our unconsolidated
U.S. oil and gas joint venture was deemed a significant
subsidiary. See Part IV — Item 15. Exhibits,
Financial Statement Schedules for Schedule III —
Financial Statements and Notes for NFR Energy LLC (“NFR
Energy”) and see Note 16 — Related-Party
Transactions for a discussion of transactions with all of these
related parties.
As of December 31, 2010 and 2009, our consolidated balance
sheets reflect our investments in unconsolidated affiliates
accounted for using the equity method totaled
$265.8 million and $305.7 million, respectively, and
our investments in unconsolidated affiliates accounted for using
the cost method totaled $1.9 million and $.9 million,
respectively. Assets held for sale include investments in
unconsolidated affiliates accounted for using the equity method
totaling $79.5 million at December 31, 2010.
Combined condensed financial data for investments in
unconsolidated affiliates, including assets classified as held
for sale, is summarized as follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Current assets
|
$ | 322,086 | $ | 354,504 | ||||
|
Long-term assets
|
1,332,212 | 1,005,605 | ||||||
|
Current liabilities
|
345,279 | 313,317 | ||||||
|
Long-term liabilities
|
460,198 | 283,945 | ||||||
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Industries Ltd. and Subsidiaries
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| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Gross revenues
|
$ | 901,742 | $ | 960,823 | $ | 827,044 | ||||||
|
Gross margin
|
241,831 | 223,005 | 142,763 | |||||||||
|
Net income (loss)
|
48,426 | (462,613 | ) | (444,470 | ) | |||||||
|
Nabors’ earnings (losses) from unconsolidated affiliates(1)
|
33,257 | (155,433 | ) | (192,548 | ) | |||||||
| (1) | Nabors’ earnings (losses) from unconsolidated affiliates included in discontinued operations, net of tax was $(10.6) million, $(59.2) million, and $(37.3) million, respectively, for the years ended December 31, 2010, 2009 and 2008. |
Cumulative undistributed (losses) earnings of our unconsolidated
affiliates included in our retained earnings as of
December 31, 2010 and 2009 totaled approximately
$(373.9) million and $(387.5) million, respectively.
Our Earnings (losses) from unconsolidated affiliates line in our
consolidated statements of income (loss) for the years ended
December 31, 2009 and 2008 include our proportionate share
of full-cost ceiling test writedowns of $189.3 million and
$207.3 million, respectively, from our unconsolidated
U.S. oil and gas joint venture. These writedowns are
included in our Oil and Gas operating segment results. Our
proportionate share of full-cost ceiling test writedowns of
$47.8 million and $21.0 million recorded for the years
ended December 31, 2009 and 2008, respectively, by our
other unconsolidated oil and gas joint ventures, SMVP and
Remora, are reflected in discontinued operations. See
Note 21 — Discontinued Operations for additional
information.
| Note 10 | Financial Instruments and Risk Concentration |
We may be exposed to certain market risks arising from the use
of financial instruments in the ordinary course of business.
These risks arise primarily as a result of potential changes in
the fair market value of financial instruments that would result
from adverse fluctuations in foreign currency exchange rates,
credit risk, interest rates, and marketable and non-marketable
security prices as discussed below.
Foreign
Currency Risk
We operate in a number of international areas and are involved
in transactions denominated in currencies other than
U.S. dollars, which exposes us to foreign exchange rate
risk or foreign currency devaluation risk. The most significant
exposures arise in connection with our operations in Venezuela
and Canada, which usually are substantially unhedged.
At various times, we utilize local currency borrowings (foreign
currency-denominated debt), the payment structure of customer
contracts and foreign exchange contracts to selectively hedge
our exposure to exchange rate fluctuations in connection with
monetary assets, liabilities, cash flows and commitments
denominated in certain foreign currencies. A foreign exchange
contract is a foreign currency transaction, defined as an
agreement to exchange different currencies at a given future
date and at a specified rate.
Credit
Risk
Our financial instruments that potentially subject us to
concentrations of credit risk consist primarily of cash
equivalents, short-term and long-term investments, oil and gas
financing receivables, accounts receivable and our
range-cap-and-floor derivative instrument. Cash equivalents such
as deposits and temporary cash investments are held by major
banks or investment firms. Our short-term and long-term
investments are managed within established guidelines which
limit the amounts that may be invested with any one issuer and
provide guidance as to issuer credit quality. We believe that
the credit risk in our cash and investment portfolio
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
is minimized as a result of the mix of our investments. In
addition, our trade receivables are with a variety of U.S.,
international and foreign-country national oil and gas
companies. Management considers this credit risk to be limited
due to the financial resources of these companies. We perform
ongoing credit evaluations of our customers and we generally do
not require material collateral. We do occasionally require
prepayment of amounts from customers whose creditworthiness is
in question prior to providing services to them. We maintain
reserves for potential credit losses, and these losses
historically have been within management’s expectations.
Interest
Rate and Marketable and Non-marketable Security Price
Risk
Our financial instruments that are potentially sensitive to
changes in interest rates include our 0.94% senior
exchangeable notes, our 5.375%, 6.15%, 9.25% and
5.0% senior notes, our range-cap-and-floor derivative
instrument, our investments in debt securities (including
corporate, asset-backed, mortgage-backed debt and mortgage-CMO
debt securities) and our investments in overseas funds that
invest primarily in a variety of public and private
U.S. and
non-U.S. securities
(including asset-backed and mortgage-backed securities, global
structured-asset securitizations, whole-loan mortgages, and
participations in whole loans and whole-loan mortgages), which
are classified as long-term investments.
We may utilize derivative financial instruments that are
intended to manage our exposure to interest rate risks. The use
of derivative financial instruments could expose us to further
credit risk and market risk. Credit risk in this context is the
failure of a counterparty to perform under the terms of the
derivative contract. When the fair value of a derivative
contract is positive, the counterparty would owe us, which can
create credit risk for us. When the fair value of a derivative
contract is negative, we would owe the counterparty, and
therefore, we would not be exposed to credit risk. We attempt to
minimize credit risk in derivative instruments by entering into
transactions with major financial institutions that have a
significant asset base. Market risk related to derivatives is
the adverse effect on the value of a financial instrument that
results from changes in interest rates. We try to manage market
risk associated with interest-rate contracts by establishing and
monitoring parameters that limit the type and degree of market
risk that we undertake.
On October 21, 2002, we entered into an interest rate swap
transaction with a third-party financial institution to hedge
our exposure to changes in the fair value of $200 million
of our fixed rate 5.375% senior notes due 2012, which has
been designated as a fair value hedge. Additionally on that
date, we purchased a LIBOR range-cap and sold a LIBOR floor, in
the form of a cashless collar, with the same third-party
financial institution with the intention of mitigating and
managing our exposure to changes in the three-month
U.S. dollar LIBOR rate. This transaction does not qualify
for hedge accounting treatment, and any change in the cumulative
fair value of this transaction will be reflected as a gain or
loss in our consolidated statements of income (loss). In June
2004, we unwound $100 million of the $200 million
range-cap-and-floor derivative instrument. During the fourth
quarter of 2005, we unwound the interest rate swap resulting in
a loss of $2.7 million, which has been deferred and will be
recognized as an increase to interest expense over the remaining
life of our 5.375% senior notes due 2012. During the year
ended December 31, 2005, we recorded interest savings of
$2.7 million related to our interest rate swap agreement
accounted for as a fair value hedge, which served to reduce
interest expense.
The fair value of our range-cap-and-floor transaction is
recorded as a derivative liability and included in other
long-term liabilities. It totaled approximately
$3.4 million and $3.3 million as of December 31,
2010 and 2009, respectively. During 2010, 2009 and 2008, we
recorded gains or (losses) of approximately $(.1) million,
$1.4 million and $(4.7) million, respectively, related
to this derivative instrument; these amounts are included in
losses (gains) on sales and retirements of long-lived assets and
other expense (income), net in our consolidated statements of
income (loss).
In September 2008 we entered into a three-month written put
option for one million of our common shares with a strike price
of $25 per share. We settled this contract during the fourth
quarter of 2008 and paid
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Industries Ltd. and Subsidiaries
NOTES TO
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cash of $22.6 million, net of the premium received on this
contract, and recognized a loss of $9.9 million which is
included in losses (gains) on sales and retirements of
long-lived assets and other expense (income), net in our
consolidated statements of income (loss).
| Note 11 | Debt |
Long-term debt consists of the following:
|
December 31,
|
December 31,
|
|||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
0.94% senior exchangeable notes due May 2011
|
$ | 1,378,178 | $ | 1,576,480 | ||||
|
5.00% senior notes due September 2020
|
697,037 | — | ||||||
|
6.15% senior notes due February 2018
|
966,276 | 965,066 | ||||||
|
9.25% senior notes due January 2019
|
1,125,000 | 1,125,000 | ||||||
|
5.375% senior notes due August 2012
|
273,977 | 273,350 | ||||||
|
Other
|
2,676 | 872 | ||||||
| 4,443,144 | 3,940,768 | |||||||
|
Less: current portion
|
1,379,018 | 163 | ||||||
| $ | 3,064,126 | $ | 3,940,605 | |||||
As of December 31, 2010, the maturities of our primary debt
for each of the five years after 2010 and thereafter are as
follows:
| Paid at Maturity | ||||
| (In thousands) | ||||
|
2011
|
$ | 1,403,455 | (1) | |
|
2012
|
275,000 | (2) | ||
|
2013
|
— | |||
|
2014
|
— | |||
|
2015
|
— | |||
|
Thereafter
|
2,800,000(3 | ) | ||
| $ | 4,478,455 | |||
| (1) | Represents our 0.94% senior exchangeable notes due May 2011. | |
| (2) | Represents our 5.375% senior notes due August 2012. | |
| (3) | Represents our 6.15% senior notes due February 2018, 9.25% senior notes due January 2019, and 5.0% senior notes due September 2020. |
0.94% Senior
Exchangeable Notes Due May 2011
As of December 31, 2010, the current portion of our
long-term debt included $1.4 billion par value of Nabors
Delaware’s 0.94% senior exchangeable notes that will
mature in May 2011.
On May 23, 2006, Nabors Delaware completed a private
placement of $2.5 billion aggregate principal amount of
0.94% senior exchangeable notes due 2011 that are fully and
unconditionally guaranteed by Nabors. On June 8, 2006, the
initial purchasers exercised their option to purchase an
additional $250 million par value of the 0.94% senior
exchangeable notes due 2011, increasing the aggregate issuance
of such notes to $2.75 billion. Nabors Delaware sold the
notes to the initial purchasers in reliance on the exemption
from
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Industries Ltd. and Subsidiaries
NOTES TO
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registration provided by Section 4(2) of the Securities
Act. The notes were reoffered by the initial purchasers of the
notes to qualified institutional buyers under Rule 144A of
the Securities Act. Nabors and Nabors Delaware filed a
registration statement on
Form S-3
pursuant to the Securities Act with respect to resale of the
notes and shares received in exchange for the notes on
August 21, 2006. The notes bear interest at a rate of 0.94%
per year payable semi-annually on May 15 and November 15,
beginning on November 15, 2006. Debt issuance costs of
$28.7 million were capitalized in connection with the
issuance of the notes in other long-term assets in our
consolidated balance sheet and are being amortized through May
2011.
As of December 31, 2010, we had purchased
$1.35 billion par value of these notes in the open market
for cash of $1.22 billion. During 2010, 2009 and 2008, we
recognized pre-tax gains (losses) of $(7.0) million,
$11.5 million and 12.2 million, respectively, all of
which are included in losses (gains) on sales and retirements of
long-lived assets and other expense (income), net in our
consolidated statements of income (loss) for the respective year.
The notes are exchangeable into cash and, if applicable,
Nabors’ common shares based on an exchange rate of the
equivalent value of 21.8221 our common shares per $1,000
principal amount of notes (which is equal to an initial exchange
price of approximately $45.83 per share), subject to adjustment
during the 30 calendar days ending at the close of business on
the business day immediately preceding the maturity date and
prior thereto only under the following circumstances:
(1) during any calendar quarter (and only during such
calendar quarter), if the closing price of Nabors’ common
shares for at least 20 trading days in the 30 consecutive
trading days ending on the last trading day of the immediately
preceding calendar quarter is more than 130% of the applicable
exchange rate; (2) during the five business day period
after any ten consecutive trading day period in which the
trading price per note for each day of that period was less than
95% of the product of the closing sale price of Nabors’
common shares and the exchange rate of the note; or
(3) upon the occurrence of specified corporate transactions
set forth in the indenture.
The notes are unsecured and are effectively junior in right of
payment to any of Nabors Delaware’s future secured debt.
The notes rank equally with any of Nabors Delaware’s other
existing and future unsubordinated debt and are senior in right
of payment to any of Nabors Delaware’s future subordinated
debt. Our guarantee of the notes is unsecured and ranks equal in
right of payment to all of our unsecured and unsubordinated
indebtedness from time to time outstanding. Holders of the notes
who exchange their notes in connection with a change in control,
as defined in the indenture, may be entitled to a make-whole
premium in the form of an increase in the exchange rate.
Additionally, in the event of a change in control, noteholders
may require Nabors Delaware to purchase all or a portion of
their notes at a purchase price equal to 100% of the principal
amount of notes, plus accrued and unpaid interest, if any. Upon
exchange of the notes, a holder will receive for each note
exchanged an amount in cash equal to the lesser of
(i) $1,000 or (ii) the exchange value, determined in
the manner set forth in the indenture. In addition, if the
exchange value exceeds $1,000 on the exchange date, a holder
will also receive a number of Nabors’ common shares for the
exchange value in excess of $1,000 equal to such excess divided
by the exchange price.
In connection with the sale of the notes in May 2006, Nabors
Delaware entered into exchangeable note hedge transactions with
respect to our common shares. The call options are designed to
cover, subject to customary anti-dilution adjustments, the net
number of our common shares that would be deliverable to
exchanging noteholders in the event of an exchange of the notes.
Nabors Delaware paid an aggregate amount of approximately
$583.6 million of the proceeds from the sale of the notes
to acquire the call options.
Nabors also entered into separate warrant transactions at the
time of the sale of the notes whereby we sold warrants that give
the holders the right to acquire approximately 60.0 million
of our common shares at a strike price of $54.64 per share. On
exercise of the warrants, we have the option to deliver cash or
our common shares equal to the difference between the then
market price and strike price. All of the warrants will be
exercisable and will expire on August 15, 2011. We received
aggregate proceeds of approximately
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Industries Ltd. and Subsidiaries
NOTES TO
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STATEMENTS — (Continued)
$421.2 million from the sale of the warrants and used
$353.4 million of the proceeds to purchase
10.0 million of our common shares.
The purchased call options and sold warrants are separate
contracts entered into by Nabors and Nabors Delaware with two
financial institutions and are not part of the terms of the
notes and do not affect the holders’ rights under the
notes. The purchased call options are expected to offset the
potential dilution upon exchange of the notes in the event the
market value of a share of our common shares at the time of
exercise is greater than the strike price of the purchased call
options, which corresponds to the initial exchange price of the
notes, subject to customary adjustments. The warrants
effectively increase the exchange price of the notes to $54.64
per common share from the perspective of Nabors, representing a
55% premium over the last reported bid price of $35.25 per share
on May 17, 2006. We recorded the exchangeable note hedge
and warrants in capital in excess of par value as of the
transaction date, and do not recognize subsequent changes in
fair value.
We continue to assess our ability to meet this obligation, along
with our other operating and capital requirements or other
potential opportunities over the next 12 months, through a
combination of cash on hand, future operating cash flows,
possible disposition of non-core assets, availability under our
unsecured revolving credit facilities and our ability to access
the capital markets, if required. We also have the ability to
defer, delay or even cancel some of the planned capital
expenditures, if necessary. We believe that through a
combination of these sources, we will have sufficient liquidity
to meet these obligations.
5.0% Senior
Notes Due September 2020
On September 14, 2010, Nabors Delaware completed a private
placement of $700 million aggregate principal amount of
5.0% senior notes due 2020, which are unsecured and fully
and unconditionally guaranteed by us. The notes are subject to
registration rights. The notes were resold by the initial
purchasers to qualified institutional buyers under
Rule 144A and to certain investors outside of the United
States under Regulation S of the Securities Act. The notes
pay interest semiannually on March 15 and September 15,
beginning on March 15, 2011 and will mature on
September 15, 2020.
The notes rank equal in right of payment to all of Nabors
Delaware’s existing and future unsubordinated indebtedness,
and senior in right of payment to all of Nabors Delaware’s
existing and future senior subordinated and subordinated
indebtedness. Our guarantee of the notes is unsecured and an
unsubordinated obligation and ranks equal in right of payments
to all of our unsecured and unsubordinated indebtedness from
time to time outstanding. In the event of a change of control
triggering event, as defined in the indenture, the holders of
the notes may require Nabors Delaware to purchase all or a
portion of the notes at a purchase price equal to 101% of their
principal amount, plus accrued and unpaid interest, if any. The
notes are redeemable in whole or in part at any time at the
option of Nabors Delaware at a redemption price, plus accrued
and unpaid interest, as specified in the indenture. Nabors
Delaware used a portion of the proceeds to repay the borrowing
under the Revolving Credit Facility (defined below) incurred to
fund the Superior Merger.
On December 14, 2010, we and Nabors Delaware filed a
registration statement on
Form S-4
under the Securities Act. The registration statement related to
the exchange offer to noteholders required under the
registration rights agreement related to the 5.0% senior
notes. On January 20, 2011, Nabors Delaware commenced an
exchange offer for the notes pursuant to the registration
statement, which was declared effective by the SEC on
January 19, 2011. The exchange offer expired on
February 23, 2011 and closed on February 28, 2011.
Prior to the issuance of the notes, we entered into a Treasury
rate lock with a total notional amount of $500 million to
hedge the risk of changes in semiannual interest payments. We
designated the Treasury rate lock derivative as a cash flow
hedge and upon settlement paid $5.7 million, due to the
change in the fair value of the derivative. The loss was
recognized as a component of accumulated other comprehensive
income in our
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Industries Ltd. and Subsidiaries
NOTES TO
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STATEMENTS — (Continued)
consolidated statement of changes in equity and will be
amortized as additional interest expense over the life of the
notes. There was no ineffectiveness associated with this hedge
during the year ended December 31, 2010.
6.15% Senior
Notes Due February 2018
On February 20, 2008, Nabors Delaware completed a private
placement of $575 million aggregate principal amount of
6.15% senior notes due 2018 with registration rights, which
are unsecured and are fully and unconditionally guaranteed by
us. On July 22, 2008, Nabors Delaware completed a private
placement of $400 million aggregate principal amount of
6.15% senior notes due 2018 with registration rights, which
are unsecured and are fully and unconditionally guaranteed by
us. These new senior notes were an additional issuance under the
indenture pursuant to which Nabors Delaware issued
$575 million 6.15% senior notes due 2018 on
February 20, 2008 described above and are subject to the
same rates, terms and conditions and together will be treated as
a single class of debt securities under the indenture (together
$975 million 6.15% senior notes due 2018). The issue
of senior notes was resold by the initial purchasers to
qualified institutional buyers under Rule 144A of the
Securities Act and to certain investors outside of the United
States under Regulation S of the Securities Act. The senior
notes bear interest at a rate of 6.15% per year, payable
semi-annually on February 15 and August 15 of each year,
beginning August 15, 2008. The senior notes will mature on
February 15, 2018.
The senior notes are unsecured and are effectively junior in
right of payment to any of Nabors Delaware’s future secured
debt. The senior notes rank equally with any of Nabors
Delaware’s other existing and future unsubordinated debt
and are senior in right of payment to any of Nabors
Delaware’s future senior subordinated debt. Our guarantee
of the senior notes is unsecured and ranks equal in right of
payment to all of our unsecured and unsubordinated indebtedness
from time to time outstanding. The senior notes are subject to
redemption by Nabors Delaware, in whole or in part, at any time
at a redemption price equal to the greater of (i) 100% of
the principal amount of the senior notes then outstanding to be
redeemed; or (ii) the sum of the present values of the
remaining scheduled payments of principal and interest,
determined in the manner set forth in the indenture. In the
event of a change in control triggering event, as defined in the
indenture, the holders of senior notes may require Nabors
Delaware to purchase all or any part of each senior note in cash
equal to 101% of the principal amount plus accrued and unpaid
interest, if any, to the date of purchase, except to the extent
Nabors Delaware has exercised its right to redeem the senior
notes. Nabors Delaware used the proceeds of the offering of the
senior notes for general corporate purposes, including the
repayment of debt.
On August 20, 2008, we and Nabors Delaware filed a
registration statement on Amendment No. 1 to
Form S-4
with the SEC with respect to an offer to exchange the combined
$975 million aggregate principal amount of
6.15% senior notes due 2018 for other notes that would be
registered and have terms substantially identical in all
material respects to these notes pursuant to the applicable
registration rights agreement, including being fully and
unconditionally guaranteed by us. On September 2, 2008, the
registration statement was declared effective by the SEC and the
exchange offer expired on October 9, 2008. On
October 16, 2008, Nabors Delaware issued $974,965,000 of
notes pursuant to the registration statement in exchange for an
equal amount of the original notes due 2018 that were properly
tendered.
9.25% Senior
Notes Due January 2019
On January 12, 2009, Nabors Delaware completed a private
placement of $1.125 billion aggregate principal amount of
9.25% senior notes due 2019 with registration rights, which
are unsecured and are fully and unconditionally guaranteed by
us. The issue of senior notes was resold by the initial
purchasers to qualified institutional buyers under
Rule 144A and to certain investors outside of the United
States under Regulation S of the Securities Act. The senior
notes bear interest at a rate of 9.25% per year, payable
semi-annually on January 15 and July 15 of each year, beginning
July 15, 2009. The senior notes will mature on
January 15, 2019.
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Industries Ltd. and Subsidiaries
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The senior notes are unsecured and are junior in right of
payment to any of Nabors Delaware’s future secured debt.
The senior notes rank equally with any of Nabors Delaware’s
other existing and future unsubordinated debt and are senior in
right of payment to any of Nabors Delaware’s future senior
subordinated debt. Our guarantee of the senior notes is
unsecured and ranks equal in right of payment to all of our
unsecured and unsubordinated indebtedness from time to time
outstanding. The senior notes are subject to redemption by
Nabors Delaware, in whole or in part, at any time at a
redemption price equal to the greater of (i) 100% of the
principal amount of the senior notes then outstanding to be
redeemed; or (ii) the sum of the present values of the
remaining scheduled payments of principal and interest,
determined in the manner set forth in the applicable indenture.
In the event of a change in control triggering event, as defined
in the indenture, the holders of senior notes may require Nabors
Delaware to purchase all or any part of each senior note in cash
equal to 101% of the principal amount plus accrued and unpaid
interest, if any, to the date of purchase, except to the extent
Nabors Delaware has exercised its right to redeem the senior
notes. Nabors Delaware is using the proceeds of the offering of
the senior notes for the repayment or repurchase of indebtedness
and general corporate purposes.
On March 30, 2009, we and Nabors Delaware filed a
registration statement on
Form S-4
under the Securities Act. The registration statement related to
the exchange offer to noteholders required under the
registration rights agreement related to the 9.25% senior
notes. On May 11, 2009 the registration statement was
declared effective by the SEC. On July 23, 2009 Nabors
Delaware issued $1,069,392,000 of notes pursuant to the
registration statement in exchange for an equal amount of the
original notes due 2019 that were properly tendered.
5.375% Senior
Notes Due August 2012
On August 22, 2002, Nabors Delaware issued
$275 million aggregate principal amount of
5.375% senior notes due 2012, which are fully and
unconditionally guaranteed by Nabors. The senior notes were
resold by a placement agent to qualified institutional buyers
under Rule 144A of the Securities Act of 1933. Interest on
the senior notes is payable semi-annually on February 15 and
August 15 of each year.
The notes are unsecured and are effectively junior in right of
payment to any of Nabors Delaware’s future secured debt.
The notes rank equal in right of payment with any of Nabors
Delaware’s future unsubordinated debt and are senior in
right of payment to any of Nabors Delaware’s subordinated
debt. The guarantee of Nabors with respect to the senior notes
issued by Nabors Delaware, is similarly unsecured and has a
similar ranking to the series of senior notes so guaranteed.
Subject to certain qualifications and limitations, the
indentures governing the senior notes issued by Nabors Delaware
limit the ability of Nabors and its subsidiaries to incur liens
and to enter into sale and lease-back transactions. In addition,
the indentures limit our ability to enter into mergers,
consolidations or transfers of all or substantially all of our
assets unless the successor company assumes their obligations
under the applicable indenture.
Revolving
Credit Facilities
On September 7, 2010, we and Nabors Delaware entered into a
credit agreement under which the lenders committed to provide to
Nabors Delaware up to $700 million under an unsecured
revolving credit facility (the “Revolving Credit
Facility”) or the (“Facility”). The Facility also
provides Nabors Delaware the option to increase the aggregate
principal amount of commitments to $850 million by adding
new lenders to the Facility or by asking existing lenders under
the Facility to increase their commitments (in each case with
the consent of the new lenders or the increasing lenders). In
January 2011, Nabors Delaware added a new lender to the Facility
and increased the total commitments under the Facility to
$750 million. We fully and unconditionally guarantee the
obligations under the Revolving Credit Facility, which matures
in four years.
99
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Borrowings under the Revolving Credit Facility bear interest, at
Nabors Delaware’s option, at either (x) the “Base
Rate” (as defined below) plus the applicable interest
margin, calculated on the basis of the actual number of days
elapsed in a year of 365 days and payable quarterly in
arrears or (y) interest periods of one, two, three or six
months at an annual rate equal to the LIBOR for the
corresponding deposits of U.S. dollars, plus the applicable
interest margin, payable on the last days of the relevant
interest periods (but in any event at least every three months).
The “Base Rate” is defined, for any day, as a
fluctuating rate per annum equal to the highest of (i) the
Federal Funds Rate, as published by the Federal Reserve Bank of
New York, plus
1
/
2
of 1%, (ii) the prime commercial lending rate of UBS AG, as
established from time to time at its Stamford Branch and
(iii) LIBOR for an interest period of one month beginning
on such day plus 1%.
On February 11, 2011, one of our subsidiaries established a
credit facility, which we unconditionally guarantee, for
approximately US$50 million.
Other
Debt Transactions
In January and February 2009, Nabors Holdings 1, ULC, one of our
wholly owned subsidiaries (“Nabors Holdings”),
repurchased $56.6 million par value of the
$225 million principal amount of its 4.875% senior
notes due August 2009 in the open market for cash totaling
$56.8 million. In August 2009, Nabors Holdings paid
$168.4 million to redeem the remaining notes. The
redemption resulted in no gain or loss as the notes were
redeemed at a price equal to their carrying value.
Short-Term
Borrowings
We had five
letter-of-credit
facilities with various banks as of December 31, 2010. We
did not have any short-term borrowings outstanding at
December 31, 2010 or 2009. Availability and borrowings
under our
letter-of-credit
facilities are as follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Credit available
|
$ | 270,263 | $ | 245,442 | ||||
|
Letters of credit outstanding, inclusive of financial and
performance guarantees
|
(70,605 | ) | (71,389 | ) | ||||
|
Remaining availability
|
$ | 199,658 | $ | 174,053 | ||||
| Note 12 | Income Taxes |
We apply the provisions of the Income Taxes Topic in the ASC
relating to uncertain tax positions. The change in our
unrecognized tax benefits for years ended December 31,
2010, 2009 and 2008 were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Balance as of January 1,
|
$ | 69,048 | $ | 51,819 | $ | 55,627 | ||||||
|
Additions based on tax positions related to the current year
|
1,026 | 4,787 | 3,990 | |||||||||
|
Additions for tax positions of prior years
|
17,060 | 12,889 | 4,168 | |||||||||
|
Reductions for tax positions of prior years
|
(4,709 | ) | (447 | ) | (10,966 | ) | ||||||
|
Settlements
|
(1,251 | ) | — | (1,000 | ) | |||||||
|
Balance as of December 31,
|
$ | 81,174 | $ | 69,048 | $ | 51,819 | ||||||
100
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The balance also represents the amount of unrecognized tax
benefits that, if recognized, would favorably impact the
effective income tax rate in future periods. As of
December 31, 2010, 2009 and 2008, we had approximately
$42.9 million, $38.5 million and $18.6 million,
respectively, of interest and penalties related to our total
gross unrecognized tax benefits. During the years ended
December 31, 2010, 2009 and 2008, we accrued and recognized
estimated interest related to unrecognized tax benefits and
penalties of approximately $5.1 million, $5.2 million
and $5.3 million, respectively. We recognize interest and
penalties related to income tax matters in the income tax
expense line item in our consolidated statements of income
(loss).
We are subject to income taxes in the United States and numerous
other jurisdictions. A number of our United States and
non-United
States income tax returns from 1995 through 2009 are currently
under audit examination. We anticipate that several of these
audits could be finalized within 12 months. It is possible
that the benefit that relates to our unrecognized tax positions
could significantly increase or decrease within 12 months.
However, based on the current status of examinations, and the
protocol for finalizing audits with the relevant tax
authorities, which could include formal legal proceedings, it is
not possible to estimate the future impact of the amount of
changes, if any, to recorded uncertain tax positions at
December 31, 2010.
Income (loss) from continuing operations before income taxes was
comprised of the following:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
United States and Other Jurisdictions:
|
||||||||||||
|
United States
|
$ | (254,897 | ) | $ | (716,694 | ) | $ | 313,704 | ||||
|
Other jurisdictions
|
336,943 | 554,623 | 417,550 | |||||||||
|
Income (loss) before income taxes from continuing operations
|
$ | 82,046 | $ | (162,071 | ) | $ | 731,254 | |||||
Income taxes have been provided based upon the tax laws and
rates in the countries in which operations are conducted and
income is earned. We are a Bermuda-exempt company. Bermuda does
not impose corporate income taxes. Our U.S. subsidiaries
are subject to a U.S. federal tax rate of 35%.
Income tax expense (benefit) from continuing operations
consisted of the following:
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Current:
|
||||||||||||
|
U.S. federal
|
$ | (137,847 | ) | $ | (15,434 | ) | $ | 59,914 | ||||
|
Outside the U.S.
|
54,779 | 84,220 | 119,889 | |||||||||
|
State
|
(748 | ) | 746 | 9,029 | ||||||||
| (83,816 | ) | 69,532 | 188,832 | |||||||||
|
Deferred:
|
||||||||||||
|
U.S. federal
|
40,731 | (148,188 | ) | 57,845 | ||||||||
|
Outside the U.S.
|
12,006 | (46,462 | ) | (44,651 | ) | |||||||
|
State
|
6,265 | (8,685 | ) | 7,634 | ||||||||
| 59,002 | (203,335 | ) | 20,828 | |||||||||
|
Income tax expense (benefit)
|
$ | (24,814 | ) | $ | (133,803 | ) | $ | 209,660 | ||||
101
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Nabors is not subject to tax in Bermuda. A reconciliation of the
differences between taxes on income (loss) before income taxes
computed at the appropriate statutory rate and our reported
provision for income taxes follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Income tax provision at statutory rate (Bermuda rate of 0%)
|
$ | — | $ | — | $ | — | ||||||
|
Taxes on U.S. and other international earnings (losses) at
greater than the Bermuda rate
|
(43,078 | ) | (130,607 | ) | 190,466 | |||||||
|
Increase in valuation allowance
|
2,407 | 6,062 | 6,604 | |||||||||
|
Effect of change in tax rate
|
40 | (9,248 | ) | (5,406 | ) | |||||||
|
Establishment of a deferred tax asset, net of valuation allowance
|
— | — | 1,990 | |||||||||
|
Tax reserves and interest
|
8,808 | 14,652 | (657 | ) | ||||||||
|
State income taxes
|
7,009 | (14,662 | ) | 16,663 | ||||||||
|
Income tax expense (benefit)
|
$ | (24,814 | ) | $ | (133,803 | ) | $ | 209,660 | ||||
|
Effective tax rate
|
(30 | )% | 83 | % | 29 | % | ||||||
Our effective income tax rate for 2010 and 2009 reflects the
disparity between losses in our U.S. operations
(attributable primarily to impairments) and income in our other
operations primarily in lower tax jurisdictions. Because the
U.S. income tax rate is higher than that of other
jurisdictions, the tax benefit from our U.S. losses was not
proportionately reduced by the tax expense from our other
operations. During 2010 and 2009, the result was a net tax
benefit. In 2009, that benefit represented a significant
percentage of our consolidated loss from continuing operations
before income taxes. Because of the manner in which that number
was derived, we do not believe it presents a meaningful basis
for comparing our 2009 effective income tax rate to either the
2010 or 2009, effective income tax rate.
The significant components of our deferred tax assets and
liabilities were as follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Deferred tax assets:
|
||||||||
|
Net operating loss carryforwards
|
$ | 1,848,956 | $ | 1,852,829 | ||||
|
Equity compensation
|
19,262 | 23,340 | ||||||
|
Deferred revenue
|
13,428 | 30,944 | ||||||
|
Tax credit and other attribute carryforwards
|
89,141 | 17,521 | ||||||
|
Insurance loss reserve
|
28,537 | 13,173 | ||||||
|
Other
|
62,324 | 114,520 | ||||||
|
Subtotal
|
2,061,648 | 2,052,327 | ||||||
|
Valuation allowance
|
(1,514,153 | ) | (1,570,890 | ) | ||||
|
Deferred tax assets
|
$ | 547,495 | $ | 481,437 | ||||
102
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Deferred tax liabilities:
|
||||||||
|
Depreciation, amortization and depletion for tax in excess of
book expense
|
$ | 1,123,622 | $ | 950,318 | ||||
|
Variable interest investments
|
75,204 | 3,064 | ||||||
|
Other
|
54,738 | 47,553 | ||||||
|
Deferred tax liability
|
1,253,564 | 1,000,935 | ||||||
|
Net deferred assets (liabilities)
|
$ | (706,069 | ) | $ | (519,498 | ) | ||
|
Balance Sheet Summary
|
||||||||
|
Net current deferred asset
|
$ | 31,510 | $ | 125,163 | ||||
|
Net noncurrent deferred asset(1)
|
33,694 | 37,559 | ||||||
|
Net current deferred liability(2)
|
(1,027 | ) | (8,793 | ) | ||||
|
Net noncurrent deferred liability
|
(770,246 | ) | (673,427 | ) | ||||
|
Net deferred asset (liability)
|
$ | (706,069 | ) | $ | (519,498 | ) | ||
| (1) | This amount is included in other long-term assets. | |
| (2) | This amount is included in accrued liabilities. |
For U.S. federal income tax purposes, we have net operating
loss (“NOL”) carryforwards of approximately
$759.3 million that, if not utilized, will expire between
2018 and 2030. The NOL carryforwards for alternative minimum tax
purposes are approximately $413 million. Additionally, we
have NOL carryforwards in other jurisdictions of approximately
$5.4 billion of which $343 million that, if not
utilized, will expire at various times from 2011 to 2030. We
provide a valuation allowance against NOL carryforwards in
various tax jurisdictions based on our consideration of existing
temporary differences and expected future earning levels in
those jurisdictions. We have recorded a deferred tax asset of
approximately $1.46 billion as of December 31, 2010
relating to NOL carryforwards that have an indefinite life in
several
non-U.S. jurisdictions.
A valuation allowance of approximately $1.46 billion has
been recognized because we believe it is more likely than not
that substantially all of the deferred tax asset will not be
realized.
103
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The NOL carryforwards by year of expiration:
| Year Ended December 31, | Total | U.S. Federal | Non-U.S. | |||||||||
| (In thousands) | ||||||||||||
|
2011
|
$ | 1,351 | $ | $ | 1,351 | |||||||
|
2012
|
8,756 | 8,756 | ||||||||||
|
2013
|
25,958 | 25,958 | ||||||||||
|
2014
|
6,019 | 6,019 | ||||||||||
|
2015
|
15,665 | 15,665 | ||||||||||
|
2016
|
23,375 | 23,375 | ||||||||||
|
2017
|
23,714 | 23,714 | ||||||||||
|
2018
|
63,796 | 33,111 | 30,685 | |||||||||
|
2019
|
40,427 | 17,722 | 22,705 | |||||||||
|
2020
|
30,944 | 30,944 | ||||||||||
|
2026
|
— | — | ||||||||||
|
2027
|
8,663 | 8,663 | ||||||||||
|
2028
|
31,385 | 31,385 | ||||||||||
|
2029
|
193,487 | 139,347 | 54,140 | |||||||||
|
2030
|
629,243 | 569,127 | 60,116 | |||||||||
|
Subtotal: expiring NOLs
|
1,102,783 | 759,307 | 343,476 | |||||||||
|
Non-expiring NOLs
|
5,071,148 | 5,071,148 | ||||||||||
|
Total
|
$ | 6,173,931 | $ | 759,307 | $ | 5,414,624 | ||||||
In addition, for state income tax purposes, we have net
operating loss carryforwards of approximately $511 million
that, if not utilized, will expire at various times from 2011 to
2030.
Under U.S. federal tax law, the amount and availability of
loss carryforwards (and certain other tax attributes) are
subject to a variety of interpretations and restrictive tests
applicable to Nabors and our subsidiaries. The utilization of
these carryforwards could be limited or effectively lost upon
certain changes in our shareholder base. Accordingly, although
we believe substantial loss carryforwards are available to us,
no assurance can be given concerning these loss carryforwards,
or whether or not they will be available in the future.
Various bills have been introduced in Congress that could reduce
or eliminate the tax benefits associated with our reorganization
as a Bermuda company. Legislation enacted by Congress in 2004
provides that a corporation that reorganized in a foreign
jurisdiction on or after March 4, 2003 be treated as a
domestic corporation for United States federal income tax
purposes. Nabors’ reorganization was completed
June 24, 2002. There has been and we expect that there may
continue to be legislation proposed in Congress from time to
time which, if enacted, could limit or eliminate the tax
benefits associated with our reorganization.
Because we cannot predict whether legislation will ultimately be
adopted, no assurance can be given that the tax benefits
associated with our reorganization will ultimately accrue to the
benefit of the Company and its shareholders. It is possible that
future changes to tax laws (including tax treaties) could impact
our ability to realize the tax savings recorded to date as well
as future tax savings resulting from our reorganization.
104
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 13 | Common Shares |
Our authorized share capital consists of 800 million common
shares, par value $.001 per share, and 25 million preferred
shares, par value $.001 per share. Common shares issued were
315,034,436 and 313,915,220 at $.001 par value as of
December 31, 2010 and 2009, respectively.
For the year ended December 31, 2008, we repurchased
8.5 million of our common shares in the open market for
$281.1 million, all of which are held in treasury. No
shares were purchased in the open market during 2009 or 2010.
From time to time, treasury shares may be reissued. When shares
are reissued, we use the weighted-average-cost method for
determining cost. The difference between the cost of the shares
and the issuance price is added to or deducted from our capital
in excess of par value account.
During 2008 we entered into a three-month written put option for
1 million of our common shares with a strike price of $25
per common share. We settled this contract during the fourth
quarter of 2008 and paid cash of $22.6 million, net of the
premium, and recognized a loss of $9.9 million which is
included in losses (gains) on sales and retirements of
long-lived assets and other expense (income), net in our
consolidated statements of income (loss).
During 2010 and 2009 our outstanding shares increased by 110,805
and 218,835, respectively, pursuant to a share settlement of
stock options exercised by Mr. Petrello. As part of these
transactions, Mr. Petrello surrendered unexercised vested
stock options to the Company with a value of approximately
$24.5 million and $5.6 million, respectively, to
satisfy the option exercise price and related income taxes for
2010 and 2009. During 2010 our outstanding shares also increased
by 22,385, pursuant to a similar share settlement of stock
options exercised by Mr. Isenberg. As part of these
transactions, Mr. Isenberg surrendered unexercised vested
stock options to the Company with a value of approximately
$50.1 million to satisfy the option exercise price and
related income taxes for 2010.
For the years ended December 31, 2010, 2009 and 2008 the
Compensation Committee of our Board of Directors granted
restricted stock awards to some of our executive officers, other
key employees, and independent directors. We awarded 538,496,
85,000 and 4,982,536 restricted shares at an average market
price of $22.15, $11.55 and $20.68 to these individuals for
2010, 2009 and 2008, respectively. See Note 6 —
Share-Based Compensation for a summary of our restricted stock
and option awards as of December 31, 2010.
For the years ended December 31, 2010, 2009 and 2008 our
employees exercised vested options to acquire .7 million,
1.5 million and 2.5 million of our common shares,
respectively, resulting in proceeds of $8.2 million,
$11.2 million and $56.6 million, respectively.
| Note 14 | Subsidiary Preferred Stock |
Superior had 75,000 shares of Series A Preferred Stock
(“preferred stock”), $0.01 par value per share,
which remained outstanding at December 31, 2010. There are
10,000,000 shares authorized. The preferred stock is
issuable in series with such voting rights, if any,
designations, powers, preferences and other rights and such
qualifications, limitations and restrictions as may be
determined by Superior’s board; the board may also fix the
number of shares constituting each series and increase or
decrease the number of shares of any series.
The preferred stock is perpetual and ranks senior to
Superior’s common stock with respect to payment of
dividends, and amounts upon liquidation, dissolution or winding
up.
We have presented the preferred stock within the mezzanine
section of our consolidated balance sheets and have accounted
for the preferred stock under the ASC Topic for Distinguishing
Liabilities from Equity.
105
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Dividends
Holders of the preferred stock are entitled to receive, when and
if declared by Superior’s board, out of assets legally
available therefor, cumulative cash dividends at the rate per
annum of $40.00 per share of preferred stock. Dividends on the
preferred stock are payable quarterly in arrears on
December 1, March 1, June 1 and September 1 of each
year (and, in the case of any undeclared and unpaid dividends,
at such additional times and for such interim periods, if any,
as determined by Superior’s board), at such annual rate.
Dividends are cumulative from the date of the original issuance
of the preferred stock, whether or not in any dividend period or
periods we have assets legally available for the payment of such
dividends.
As of December 31, 2010, dividends on outstanding shares of
preferred stock had been declared and paid in full with respect
to each quarter since its initial issuance.
Liquidation
Preference
Holders of preferred stock are entitled to receive, in the event
that Superior is liquidated, dissolved or wound up, whether
voluntarily or involuntarily, $1,000 per share (the
“Liquidation Value”) plus an amount per share equal to
all dividends undeclared and unpaid thereon to the date of final
distribution (the “Liquidation Preference”), and no
more. Until the holders of preferred stock have been paid the
Liquidation Preference in full, Superior may not make any
payment to any holder of stock that ranks junior to the
preferred stock upon liquidation, dissolution or winding up. As
of December 31, 2010, the preferred stock had a total
Liquidation Preference of $75.0 million.
Redemption
The preferred stock is redeemable, in whole or in part and at
Superior’s option, at any time on or after
November 18, 2013, for a redemption price of 101% of the
Liquidation Value, plus all accrued dividends. The redemption
price is payable in cash.
As a result of the Superior Merger, each share of preferred
stock is convertible, at the option of the holder thereof, into
$22.12 for each share of Superior common stock into which the
preferred share would have been convertible prior to the
Superior Merger (a “deemed common share”). The
preferred shares had a conversion price of $25.00 per deemed
common share prior to the Superior Merger (equivalent to a
conversion rate of 40 deemed common shares for each share of
preferred stock), representing 3,000,000 deemed common shares.
This results in a redemption value of $66.4 million at
December 31, 2010, payable in cash. The right to convert
shares of preferred stock that may be called for redemption will
terminate at the close of business on the day preceding a
redemption date.
Voting
Rights
Except as otherwise required from time to time by applicable law
or upon certain events of default, the holders of preferred
stock have no voting rights, and their consent is not required
for taking any corporate action. When and if the holders of the
preferred stock are entitled to vote, each holder will be
entitled to one vote per share.
| Note 15 | Pension, Postretirement and Postemployment Benefits |
Pension
Plans
In conjunction with our acquisition of Pool Energy Services Co.
(“Pool”) in November 1999, we acquired the assets and
liabilities of a defined benefit pension plan, the Pool Company
Retirement Income Plan (the “Pool Pension Plan”).
Benefits under the Pool Pension Plan are frozen and participants
were fully vested in their accrued retirement benefit on
December 31, 1998.
106
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Summarized information on the Pool Pension Plan is as follows:
| Pension Benefits | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Change in benefit obligation:
|
||||||||
|
Benefit obligation at beginning of year
|
$ | 18,865 | $ | 17,781 | ||||
|
Interest cost
|
1,116 | 1,093 | ||||||
|
Actuarial loss (gain)
|
1,289 | 590 | ||||||
|
Benefit payments
|
(642 | ) | (599 | ) | ||||
|
Benefit obligation at end of year(1)
|
$ | 20,628 | $ | 18,865 | ||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of year
|
$ | 14,058 | $ | 12,113 | ||||
|
Actual (loss) return on plan assets
|
1,364 | 1,902 | ||||||
|
Employer contribution
|
439 | 642 | ||||||
|
Benefit payments
|
(642 | ) | (599 | ) | ||||
|
Fair value of plan assets at end of year
|
$ | 15,219 | $ | 14,058 | ||||
|
Funded status:
|
||||||||
|
Underfunded status at end of year
|
$ | (5,409 | ) | $ | (4,807 | ) | ||
|
Amounts recognized in consolidated balance sheets:
|
||||||||
|
Other long-term liabilities
|
$ | (5,409 | ) | $ | (4,807 | ) | ||
|
Components of net periodic benefit cost (recognized in our
consolidated statements of income):
|
||||||||
|
Interest cost
|
$ | 1,116 | $ | 1,093 | ||||
|
Expected return on plan assets
|
(909 | ) | (794 | ) | ||||
|
Recognized net actuarial loss
|
457 | 545 | ||||||
|
Net periodic benefit cost
|
$ | 664 | $ | 844 | ||||
|
Weighted-average assumptions:
|
||||||||
|
Weighted-average discount rate
|
5.50 | % | 6.00 | % | ||||
|
Expected long-term rate of return on plan assets
|
6.50 | % | 6.50 | % | ||||
| (1) | As of December 31, 2010 and 2009, the accumulated benefit obligation was the same as the projected benefit obligation. |
For the years ended December 31, 2010, 2009 and 2008, the
net actuarial loss amounts included in accumulated other
comprehensive income (loss) in the consolidated statements of
changes in equity were approximately $(6.7) million,
$(6.3) million and $(7.4) million, respectively. There
were no other components, such as prior service costs or
transition obligations relating to pension costs recorded within
accumulated other comprehensive income (loss) during 2010, 2009
and 2008.
The amount included in accumulated other comprehensive income
(loss) in the consolidated statements of changes in equity that
is expected to be recognized as a component of net periodic
benefit cost during 2011 is approximately $.5 million.
We analyze the historical performance of investments in equity
and debt securities, together with current market factors such
as inflation and interest rates to help us make assumptions
necessary to estimate a long-term rate of return on plan assets.
Once this estimate is made, we review the portfolio of plan
assets and make
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
adjustments thereto that we believe are necessary to reflect a
diversified blend of investments in equity and debt securities
that is capable of achieving the estimated long-term rate of
return without assuming an unreasonable level of investment risk.
The following table sets forth, by level within the fair value
hierarchy, the investments in the Pool Pension Plan as of
December 31, 2010. The investments’ fair value
measurement level within the fair value hierarchy is classified
in its entirety based on the lowest level of input that is
significant to the measurement.
| Fair Value as of December 31, 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Assets: (1)
|
||||||||||||||||
|
Cash
|
$ | — | $ | 361 | $ | — | $ | 361 | ||||||||
|
Short-term investments:
|
||||||||||||||||
|
Available-for-sale
equity securities(2)
|
— | 8,491 | — | 8,491 | ||||||||||||
|
Available-for-sale
debt securities(3)
|
— | 6,368 | — | 6,368 | ||||||||||||
|
Total investments
|
— | 14,859 | — | 14,859 | ||||||||||||
|
Total
|
$ | — | $ | 15,220 | $ | — | $ | 15,220 | ||||||||
| (1) | Includes investments in collective trust funds that are valued based on the fair value of the underlying investments using quoted prices in active markets or other significant inputs that are deemed observable. | |
| (2) | Includes funds that invest primarily in U.S. common stocks and foreign equity securities. | |
| (3) | Includes funds that invest primarily in investment grade debt. |
The measurement date used to determine pension measurements for
the plan is December 31.
Our weighted-average asset allocations as of December 31,
2010 and 2009, by asset category are as follows:
| Pension Benefits | ||||||||
| 2010 | 2009 | |||||||
|
Cash
|
2 | % | 3 | % | ||||
|
Equity securities
|
56 | % | 55 | % | ||||
|
Debt securities
|
42 | % | 42 | % | ||||
|
Total
|
100 | % | 100 | % | ||||
We invest plan assets based on a total return on investment
approach, pursuant to which the plan assets include a
diversified blend of investments in equity and debt securities
toward a goal of maximizing the long-term rate of return without
assuming an unreasonable level of investment risk. We determine
the level of risk based on an analysis of plan liabilities, the
extent to which the value of the plan assets satisfies the plan
liabilities and our financial condition. Our investment policy
includes target allocations approximating 55% investment in
equity securities and 45% investment in debt securities. The
equity portion of the plan assets represents growth and value
stocks of small, medium and large companies. We measure and
monitor the investment risk of the plan assets both on a
quarterly basis and annually when we assess plan liabilities.
We expect to contribute approximately $1.3 million to the
Pool Pension Plan in 2011. This is based on the sum of
(1) the minimum contribution for the 2010 plan year that
will be made in 2011 and (2) the estimated minimum required
quarterly contributions for the 2011 plan year. We made
contributions to the Pool Pension Plan in 2010 and 2009 totaling
$.1 million and $.6 million, respectively.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As of December 31, 2010, we expect that benefits to be paid
in each of the next five years after 2010 and in the aggregate
for the five years thereafter will be as follows:
| (In thousands) | ||||
|
2011
|
$ | 715 | ||
|
2012
|
777 | |||
|
2013
|
879 | |||
|
2014
|
1,007 | |||
|
2015
|
1,116 | |||
|
2016 — 2020
|
6,830 | |||
Some of our employees are covered by defined contribution plans.
Our contributions to the plans totaled $13.6 million and
$19.8 million for the years ended December 31, 2010
and 2009, respectively. Nabors does not provide post-employment
benefits to its employees.
Post-retirement
Benefits Other Than Pensions
Prior to the date of our acquisition, Pool provided certain
post-retirement healthcare and life insurance benefits to
eligible retirees who had attained specific age and years of
service requirements. Nabors terminated this plan at the date of
acquisition (November 24, 1999). A liability of
approximately $.2 million was recorded in our consolidated
balance sheets as of each of December 31, 2010 and 2009, to
cover the estimated costs of beneficiaries covered by the plan
at the date of acquisition.
| Note 16 | Related-Party Transactions |
Nabors and its Chairman and Chief Executive Officer, its Deputy
Chairman, President and Chief Operating Officer, and certain
other key employees entered into split-dollar life insurance
agreements, pursuant to which we pay a portion of the premiums
under life insurance policies with respect to these individuals
and, in some instances, members of their families. These
agreements provide that we are reimbursed for the premium
payments upon the occurrence of specified events, including the
death of an insured individual. Any recovery of premiums paid by
Nabors could be limited to the cash surrender value of the
policies under certain circumstances. As such, the values of
these policies are recorded at their respective cash surrender
values in our consolidated balance sheets. We have made premium
payments to date totaling $11.7 million related to these
policies. The cash surrender value of these policies of
approximately $9.5 million and $9.3 million is
included in other long-term assets in our consolidated balance
sheets as of December 31, 2010 and 2009, respectively.
Under the Sarbanes-Oxley Act of 2002, the payment of premiums by
Nabors under the agreements with our Chairman and Chief
Executive Officer and with our Deputy Chairman, President and
Chief Operating Officer could be deemed to be prohibited loans
by us to these individuals. Consequently, we have paid no
premiums related to our agreements with these individuals since
the adoption of the Sarbanes-Oxley Act.
In the ordinary course of business, we enter into various rig
leases, rig transportation and related oilfield services
agreements with our unconsolidated affiliates at market prices.
Revenues from business transactions with these affiliated
entities totaled $271.6 million, $327.3 million and
$285.3 million for the years ended December 31, 2010,
2009 and 2008, respectively. Expenses from business transactions
with these affiliated entities totaled $3.4 million,
$9.8 million and $9.6 million for the years ended
December 31, 2010, 2009 and 2008, respectively.
Additionally, we had accounts receivable from these affiliated
entities of $97.8 million and $104.2 million as of
December 31, 2010 and 2009, respectively. We had accounts
payable to these affiliated entities of $12.7 million and
$14.8 million as of December 31, 2010 and 2009,
respectively, and long-term payables with these affiliated
entities of $.8 million as of each of December 31,
2010 and 2009, respectively, which are included in other
long-term liabilities.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In addition to the equity investment in our unconsolidated
U.S. oil and gas joint venture, in April 2010 we purchased
$20.0 million face value of NFR Energy LLC’s
9.75% senior notes. These notes mature in 2017 with
interest payable semi-annually on February 15 and
August 15. During 2010, we recognized $1.4 million in
interest income from these notes.
We own an interest in Shona Energy Company, LLC
(“Shona”), a company of which Mr. Payne, an
independent member of our Board of Directors, is the Chairman
and Chief Executive Officer. During the fourth quarter of 2008,
we purchased 1.8 million common shares of Shona for
$.9 million. During the first quarter of 2010, we purchased
shares of Shona’s preferred stock and warrants to purchase
additional common shares for $.9 million. We currently hold
a minority interest of approximately 10% of the issued and
outstanding shares of Shona.
| Note 17 | Commitments and Contingencies |
Commitments
Leases
Nabors and its subsidiaries occupy various facilities and lease
certain equipment under various lease agreements.
The minimum rental commitments under capital leases, with lease
terms in excess of one year subsequent to December 31,
2010, are as follows:
| (In thousands) | ||||
|
2011
|
$ | 2,201 | ||
|
2012
|
1,265 | |||
|
2013
|
546 | |||
|
2014
|
224 | |||
|
2015
|
61 | |||
|
Thereafter
|
— | |||
| $ | 4,297 | |||
The minimum rental commitments under non-cancelable operating
leases, with lease terms in excess of one year subsequent to
December 31, 2010, are as follows:
| (In thousands) | ||||
|
2011
|
$ | 25,749 | ||
|
2012
|
18,501 | |||
|
2013
|
14,273 | |||
|
2014
|
10,315 | |||
|
2015
|
4,358 | |||
|
Thereafter
|
932 | |||
| $ | 74,128 | |||
The above amounts do not include property taxes, insurance or
normal maintenance that the lessees are required to pay. Rental
expense relating to operating leases with terms greater than
30 days amounted to $26.7 million, $25.5 million
and $29.4 million for the years ended December 31,
2010, 2009 and 2008, respectively.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Employment
Contracts
We have entered into employment contracts with certain of our
employees. Our minimum salary and bonus obligations under these
contracts as of December 31, 2010 are as follows:
| (In thousands) | ||||
|
2011
|
$ | 11,965 | ||
|
2012
|
11,965 | |||
|
2013
|
4,070 | |||
|
2014
|
319 | |||
|
2015 and thereafter
|
— | |||
| $ | 28,319 | |||
Nabors’ Chairman and Chief Executive Officer, Eugene M.
Isenberg, and its Deputy Chairman, President and Chief Operating
Officer, Anthony G. Petrello, had employment agreements
(“prior employment agreements”) in effect through the
first quarter of 2009. Effective April 1, 2009, the Company
entered into amended and restated employment agreements
(“new employment agreements”) with them which extended
the terms through March 30, 2013.
For the three months ended March 31, 2009, the prior
employment agreements provided for annual cash bonuses in an
amount equal to 6% and 2%, for Messrs. Isenberg and
Petrello, respectively, of Nabors’ net cash flow (as
defined in the respective employment agreements) in excess of
15% of the average shareholders’ equity for each fiscal
year. Mr. Petrello’s bonus was subject to a minimum of
$700,000 per year.
Effective April 1, 2009, the new employment agreements for
Messrs. Isenberg and Petrello amend and restate the prior
employment agreements. The new employment agreements provide for
an extension of the employment term through March 30, 2013,
with automatic one-year extensions beginning April 1, 2011,
unless either party gives notice of non-renewal. The base
salaries for Messrs. Isenberg and Petrello were increased
to $1.3 million and $1.1 million, respectively.
Mr. Isenberg has agreed to donate the after-tax proceeds of
his base salary to an educational fund intended to benefit
Company employees or other worthy candidates.
On June 29, 2009, the new employment agreements for
Messrs. Isenberg and Petrello were amended to provide for a
reduction in the annual rate of base salary payable to each of
Messrs. Isenberg and Petrello to $1.17 million per
year and $990,000 per year, respectively, for the period from
June 29, 2009 to December 27, 2009. On
December 28, 2009, the agreements were further amended to
extend through June 27, 2010 the previously agreed salary
reduction.
In addition to a base salary, the new employment agreements
provide for annual cash bonuses in an amount equal to 2.25% and
1.5%, for Messrs. Isenberg and Petrello, respectively, of
Nabors’ net cash flow (as defined in the respective
employment agreements) in excess of 15% of the average
shareholders’ equity for each fiscal year. For 2010, the
annual cash bonuses for Messrs. Isenberg and Petrello
pursuant to the formulas described in their employment
agreements were $9.7 million and $6.5 million,
respectively. The new employment agreements also provide a
quarterly deferred bonus of $.6 million and
$.25 million, respectively, to the accounts of
Messrs. Isenberg and Petrello under Nabors’ executive
deferred compensation plan for each quarter they are employed
beginning June 30, 2009 and, in Mr. Petrello’s
case, ending March 30, 2019.
Messrs. Isenberg and Petrello also are eligible for awards
under Nabors’ equity plans, may participate in annual
long-term incentive programs and pension and welfare plans on
the same basis as other executives, and may receive special
bonuses from time to time as determined by the Board of
Directors. The new employment agreements effectively eliminated
the risk of forfeiture of outstanding stock awards. Accordingly,
we recognized compensation expense during the second quarter of
2009 with respect to all previously granted unvested awards to
Messrs. Isenberg and Petrello. As of December 31,
2010, there was no unrecognized
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
compensation expense related to restricted stock and stock
option awards for either Mr. Isenberg or Mr. Petrello.
Termination in the event of death, disability, or
termination without cause (including in the event of a Change in
Control)
.
The new employment agreements
provide for severance payments in the event that either
Mr. Isenberg’s or Mr. Petrello’s employment
agreement is terminated (i) upon death or disability,
(ii) by Nabors prior to the expiration date of the
employment agreement for any reason other than for Cause (as
defined in the respective employment agreements), or
(iii) by either individual for Constructive Termination
Without Cause, each as defined in the respective employment
agreements. Termination in the event of a Change in Control (as
defined in the respective employment agreements) is considered a
Constructive Termination Without Cause. Mr. Isenberg would
be entitled to receive within 30 days of any such
triggering event a payment of $100 million.
Mr. Petrello would be entitled to receive within
30 days of his death or disability a payment of
$50 million or in the event of Termination Without Cause or
Constructive Termination Without Cause, a payment based on a
formula of three times the average of his base salary and annual
bonus (calculated as though the bonus formula under the new
employment agreement had been in effect) paid during the three
fiscal years preceding the termination. If, by way of example,
Mr. Petrello were Terminated Without Cause subsequent to
December 31, 2010, his payment would be approximately
$34 million. The formula will be further reduced to two
times the average stated above effective April 1, 2015.
The Company does not have insurance to cover its obligations in
the event of death, disability, or termination without cause for
either Messrs. Isenberg or Petrello and the Company has not
recorded an expense or accrued a liability relating to these
potential obligations.
In addition, under the new employment agreements, the affected
individual would be entitled to receive (a) any unvested
restricted stock or stock options outstanding, which would
immediately and fully vest; (b) any amounts earned, accrued
or owing to the executive but not yet paid (including executive
benefits, life insurance, disability benefits and reimbursement
of expenses and perquisites), which would be continued through
the later of the expiration date or three years after the
termination date; (c) continued participation in medical,
dental and life insurance coverage until the executive received
equivalent benefits or coverage through a subsequent employer or
until the death of the executive or his spouse, whichever were
later; and (d) any other or additional benefits in
accordance with applicable plans and programs of Nabors. The
vesting of unvested equity awards would not result in the
recognition of any additional compensation expense, as all
compensation expense related to Messrs. Isenberg’s and
Petrello’s outstanding awards has been recognized as of
December 31, 2010. In addition, the new employment
agreements eliminate all tax
gross-ups,
including without limitation tax
gross-ups
on
golden parachute excise taxes, which applied under the prior
employment agreements. Estimates of the cash value of
Nabors’ obligations to Messrs. Isenberg and Petrello
under (b), (c) and (d) above are included in the
payment amounts above.
Other Obligations
.
In addition
to salary and bonus, each of Messrs. Isenberg and Petrello
receive group life insurance at an amount at least equal to
three times their respective base salaries, various split-dollar
life insurance policies, reimbursement of expenses, various
perquisites and a personal umbrella insurance policy in the
amount of $5 million. Premiums payable under the
split-dollar life insurance policies were suspended as a result
of the adoption of the Sarbanes-Oxley Act of 2002.
Contingencies
Income
Tax Contingencies
We are subject to income taxes in the United States and numerous
other jurisdictions. Significant judgment is required in
determining our worldwide provision for income taxes. In the
ordinary course of our business, there are many transactions and
calculations where the ultimate tax determination is uncertain.
We are regularly audited by tax authorities. Although we believe
our tax estimates are reasonable, the final
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
determination of tax audits and any related litigation could be
materially different than what is reflected in income tax
provisions and accruals. An audit or litigation could materially
affect our financial position, income tax provision, net income,
or cash flows in the period or periods challenged.
It is possible that future changes to tax laws (including tax
treaties) could impact our ability to realize the tax savings
recorded to date as well as future tax savings, resulting from
our 2002 corporate reorganization. See Note 12 —
Income Taxes for additional discussion.
On September 14, 2006, Nabors Drilling International
Limited, one of our wholly owned Bermuda subsidiaries
(“NDIL”), received a Notice of Assessment (the
“Notice”) from Mexico’s federal tax authorities
in connection with the audit of NDIL’s Mexico branch for
2003. The Notice proposes to deny depreciation expense
deductions relating to drilling rigs operating in Mexico in
2003. The Notice also proposes to deny a deduction for payments
made to an affiliated company for the procurement of labor
services in Mexico. The amount assessed was approximately
$19.8 million (including interest and penalties). Nabors
and its tax advisors previously concluded that the deductions
were appropriate and more recently that the government’s
position lacks merit. NDIL’s Mexico branch took similar
deductions for depreciation and labor expenses from 2004 to
2008. On June 30, 2009, the government proposed similar
assessments against the Mexico branch of another wholly owned
Bermuda subsidiary, Nabors Drilling International II Ltd.
(“NDIL II”) for 2006. We anticipate that a similar
assessment will eventually be proposed against NDIL for 2004
through 2008 and against NDIL II for 2007 to 2010. We believe
that the potential assessments will range from $6 million
to $26 million per year for the period from 2004 to 2009,
and in the aggregate, would be approximately $90 million to
$95 million. Although we believe that any assessments
related to the 2004 to 2010 years lack merit, a reserve has
been recorded in accordance with GAAP. The statute of
limitations for NDIL’s 2004 tax year recently expired.
Accordingly, during the fourth quarter of 2010, we released
$7.4 million from our tax reserves, which represented the
reserve recorded for that tax year. If these additional
assessments were made and we ultimately did not prevail, we
would be required to recognize additional tax for the amount in
excess of the current reserve.
Self-Insurance
We estimate the level of our liability related to insurance and
record reserves for these amounts in our consolidated financial
statements. Our estimates are based on the facts and
circumstances specific to existing claims and our past
experience with similar claims. These loss estimates and
accruals recorded in our financial statements for claims have
historically been reasonable in light of the actual amount of
claims paid. Although we believe our insurance coverage and
reserve estimates are reasonable, a significant accident or
other event that is not fully covered by insurance or
contractual indemnity could occur and could materially affect
our financial position and results of operations for a
particular period.
We self-insure for certain losses relating to workers’
compensation, employers’ liability, general liability,
automobile liability and property damage. Some workers’
compensation claims are subject to a minimum $1.0 million
deductible liability, plus an additional $3.0 million
corridor deductible. Some employers’ liability and marine
employers’ liability claims are subject to a
$2.0 million per-occurrence deductible. Some automobile
liability is subject to a $.5 million per-occurrence
deductible, plus an additional $1.0 million corridor
deductible. General liability claims are subject to a
$5.0 million per-occurrence deductible.
In addition, we are subject to a $5.0 million deductible
for all land rigs and for offshore rigs. This applies to all
kinds of risks of physical damage except for named windstorms in
the U.S. Gulf of Mexico for which we are self-insured.
Political risk insurance is procured for select operations in
South America, Africa, the Middle East and Asia. Losses are
subject to a $.25 million deductible, except for Colombia,
which is subject to a $.5 million deductible. There is no
assurance that such coverage will adequately protect Nabors
against liability from all potential consequences.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As of December 31, 2010 and 2009, our self-insurance
accruals totaled $145.6 million and $139.0 million,
respectively, and our related insurance recoveries/receivables
were $9.0 million and $12.9 million, respectively.
Litigation
Nabors and its subsidiaries are defendants or otherwise involved
in a number of lawsuits in the ordinary course of business. We
estimate the range of our liability related to pending
litigation when we believe the amount and range of loss can be
estimated. We record our best estimate of a loss when the loss
is considered probable. When a liability is probable and there
is a range of estimated loss with no best estimate in the range,
we record the minimum estimated liability related to the
lawsuits or claims. As additional information becomes available,
we assess the potential liability related to our pending
litigation and claims and revise our estimates. Due to
uncertainties related to the resolution of lawsuits and claims,
the ultimate outcome may differ from our estimates. In the
opinion of management and based on liability accruals provided,
our ultimate exposure with respect to these pending lawsuits and
claims is not expected to have a material adverse effect on our
consolidated financial position or cash flows, although they
could have a material adverse effect on our results of
operations for a particular reporting period.
On July 5, 2007, we received an inquiry from the United
States Department of Justice relating to its investigation of
one of our vendors and compliance with the Foreign Corrupt
Practices Act. The inquiry relates to transactions with and
involving Panalpina, which provided freight forwarding and
customs clearance services to some of our affiliates. To date,
the inquiry has focused on transactions in Kazakhstan, Saudi
Arabia, Algeria and Nigeria. The Audit Committee of our Board of
Directors has engaged outside counsel to review some of our
transactions with this vendor, has received periodic updates at
its regularly scheduled meetings, and the Chairman of the Audit
Committee has received updates between meetings as circumstances
warrant. The investigation includes a review of certain amounts
paid to and by Panalpina in connection with obtaining permits
for the temporary importation of equipment and clearance of
goods and materials through customs. Both the SEC and the United
States Department of Justice have been advised of our
investigation. The ultimate outcome of this investigation or the
effect of implementing any further measures that may be
necessary to ensure full compliance with applicable laws cannot
be determined at this time.
A court in Algeria entered a judgment of approximately
$19.7 million against us related to alleged customs
infractions in 2009. We believe we did not receive proper notice
of the judicial proceedings, and that the amount of the judgment
is excessive. We have asserted the lack of legally required
notice as a basis for challenging the judgment on appeal to the
Algeria Supreme Court. Based upon our understanding of
applicable law and precedent, we believe that this challenge
will be successful. We do not believe that a loss is probable
and have not accrued any amounts related to this matter.
However, the ultimate resolution and the timing thereof are
uncertain. If we are ultimately required to pay a fine or
judgment related to this matter, the amount of the loss could
range from approximately $140,000 to $19.7 million.
In August 2010, Nabors and its wholly owned subsidiary, Diamond
Acquisition Corp. (“Diamond”) were sued in three
putative shareholder class actions. Two of the cases were
dismissed. The remaining case pending,
Jordan Denney,
Individually and on Behalf of All Others Similarly
Situated v. David E. Wallace, et al.,
Civil Action
No. 10-1154,
is pending in the United States District Court for the Western
District of Pennsylvania. The suits were brought against
Superior, the individual members of its board of directors,
certain of Superior’s senior officers, Nabors and Diamond.
The complaints alleged that Superior’s officers and
directors violated various provisions of the Exchange Act and
breached their fiduciary duties in connection with the Superior
Merger, and that Nabors and Diamond aided and abetted these
violations. The complaints sought injunctive relief, including
an injunction against the consummation of the Superior Merger,
monetary damages, and attorney’s fees and costs. The claim
against Superior and its directors is covered by insurance after
a deductible amount. We anticipate settling the claims in the
claims in the first or second quarter of 2011, and that any
settlement will be funded by Superior’s insurers to the
extent it exceeds our deductible.
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Off-Balance
Sheet Arrangements (Including Guarantees)
We are a party to some transactions, agreements or other
contractual arrangements defined as “off-balance sheet
arrangements” that could have a material future effect on
our financial position, results of operations, liquidity and
capital resources. The most significant of these off-balance
sheet arrangements involve agreements and obligations under
which we provide financial or performance assurance to third
parties. Certain of these agreements serve as guarantees,
including standby letters of credit issued on behalf of
insurance carriers in conjunction with our workers’
compensation insurance program and other financial surety
instruments such as bonds. In addition, we have provided
indemnifications, which serve as guarantees, to some third
parties. These guarantees include indemnification provided by
Nabors to our share transfer agent and our insurance carriers.
We are not able to estimate the potential future maximum
payments that might be due under our indemnification guarantees.
Management believes the likelihood that we would be required to
perform or otherwise incur any material losses associated with
any of these guarantees is remote. The following table
summarizes the total maximum amount of financial guarantees
issued by Nabors:
| Maximum Amount | ||||||||||||||||||||
| 2011 | 2012 | 2013 | Thereafter | Total | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Financial standby letters of credit and other financial surety
instruments
|
$ | 83,010 | $ | 525 | $ | 12,158 | $ | — | $ | 95,693 | ||||||||||
| Note 18 | Earnings (Losses) Per Share |
We include unvested restricted stock awards in the calculation
of basic and diluted earnings per share using the two-class
method as required by the Earnings Per Share Topic of the ASC.
115
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A reconciliation of the numerators and denominators of the basic
and diluted earnings (losses) per share computations is as
follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands, except per share amounts) | ||||||||||||
|
Net income (loss) (numerator):
|
||||||||||||
|
Income (loss) from continuing operations, net of tax
|
$ | 106,110 | $ | (28,268 | ) | $ | 521,594 | |||||
|
Less: net (income) loss attributable to noncontrolling interest
|
(85 | ) | 342 | (3,927 | ) | |||||||
|
Net income (loss) from continuing operations — basic
|
106,025 | (27,926 | ) | 517,667 | ||||||||
|
Add interest expense on assumed conversion of our zero coupon
convertible/exchangeable senior debentures/notes, net of tax:
|
||||||||||||
|
0.94% senior exchangeable notes due 2011(1)
|
— | — | — | |||||||||
|
Zero coupon exchangeable notes due 2023(2)
|
— | — | — | |||||||||
|
Adjusted net income (loss) attributable to Nabors —
diluted
|
$ | 106,025 | $ | (27,926 | ) | $ | 517,667 | |||||
|
Earnings (losses) per share:
|
||||||||||||
|
Basic from continuing operations
|
$ | .37 | $ | (.10 | ) | $ | 1.84 | |||||
|
Diluted from continuing operations
|
$ | .37 | $ | (.10 | ) | $ | 1.80 | |||||
|
Income from discontinued operations, net of tax
|
$ | (11,330 | ) | $ | (57,620 | ) | $ | (41,930 | ) | |||
|
Earnings (losses) per share, discontinued operations:
|
||||||||||||
|
Basic from discontinued operations
|
$ | (.04 | ) | $ | (.20 | ) | $ | (.15 | ) | |||
|
Diluted from discontinued operations
|
$ | (.04 | ) | $ | (.20 | ) | $ | (.15 | ) | |||
|
Shares (denominator):
|
||||||||||||
|
Weighted-average number of shares outstanding —
basic(3)
|
285,145 | 283,326 | 281,622 | |||||||||
|
Net effect of dilutive stock options, warrants and restricted
stock awards based on the if-converted method
|
4,851 | — | 5,332 | |||||||||
|
Assumed conversion of our zero coupon convertible/exchangeable
senior debentures/notes:
|
||||||||||||
|
0.94% senior exchangeable notes due 2011(1)
|
— | — | — | |||||||||
|
Zero coupon exchangeable notes due 2023(2)
|
— | — | 1,282 | |||||||||
|
Weighted-average number of shares outstanding — diluted
|
289,996 | 283,326 | 288,236 | |||||||||
| (1) | Diluted earnings (losses) per share for the years ended December 31, 2010, 2009 and 2008 exclude any incremental shares issuable upon exchange of the 0.94% senior exchangeable notes due 2011. As of December 31, 2010, we have purchased $1.3 billion par value of these notes in the open market, leaving approximately $1.4 billion par value outstanding. The number of shares that we would be required to issue upon exchange consists of only the incremental shares that would be issued above the principal amount of the notes, as we are required to pay cash up to the principal amount of the notes exchanged. We would issue an incremental number of shares only upon exchange of these notes. Such shares are included in the calculation of the weighted-average number of shares outstanding in our diluted earnings per share calculation only when our stock price exceeds $45.83 as of the last trading day of the quarter and the average price of our shares for the ten consecutive trading days beginning on the third business day after the last trading day of the quarter exceeds $45.83, which did not occur during any period for the years ended December 31, 2010, 2009 and 2008. |
116
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Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (2) | In June and July 2008 Nabors Delaware paid cash of $171.8 million and $528.2 million, respectively, to redeem all of the notes. In addition to the $700 million in cash, we issued 5.25 million common shares with a fair value of $249.8 million, which equated to the excess of the exchange value of the notes over their principal amount. Because the conversion was completed during 2008, diluted earnings per share for the year ended December 31, 2008 reflect the conversion of the zero coupon senior exchangeable notes due 2023 which included the effect of the 5.25 million shares in the calculation of the weighted-average number of basic shares outstanding. | |
| (3) | On July 31, 2009, the exchangeable shares of Nabors Exchangeco were exchanged for Nabors’ common shares on a one-for-one basis. Basic shares outstanding includes the following weighted-average number of common shares and restricted stock of Nabors and weighted-average number of exchangeable shares of Nabors Exchangeco, respectively: 285.1 million shares cumulatively for the year ended December 31, 2010; 283.2 million and .1 million shares for the year ended December 31, 2009; and 281.5 million and .1 million shares for the year ended December 31, 2008. |
For all periods presented, the computation of diluted earnings
(losses) per Nabors’ share excludes outstanding stock
options and warrants with exercise prices greater than the
average market price of Nabors’ common shares, because
their inclusion would be anti-dilutive and because they are not
considered participating securities. The average number of
options and warrants that were excluded from diluted earnings
(losses) per share that would potentially dilute earnings per
share in the future was 14,004,749, 34,113,887 and
7,416,865 shares during the years ended December 31,
2010, 2009 and 2008, respectively. In any period during which
the average market price of Nabors’ common shares exceeds
the exercise prices of these stock options and warrants, such
stock options and warrants will be included in our diluted
earnings (losses) per share computation using the if-converted
method of accounting. Restricted stock will be included in our
basic and diluted earnings (losses) per share computation using
the two-class method of accounting in all periods because such
stock is considered participating securities.
| Note 19 | Supplemental Balance Sheet, Income Statement and Cash Flow Information |
At December 31, 2010, other long-term assets included a
deposit of $40 million of restricted funds held at a
financial institution to assure future credit availability for
an unconsolidated affiliate. This cash is excluded from cash and
cash equivalents in the Consolidated Balance Sheets and
Statements of Cash Flows.
Accrued liabilities include the following:
|
December 31,
|
December 31,
|
|||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Accrued compensation
|
$ | 116,680 | $ | 79,195 | ||||
|
Deferred revenue
|
88,389 | 57,563 | ||||||
|
Other taxes payable
|
25,227 | 33,126 | ||||||
|
Workers’ compensation liabilities
|
31,944 | 31,944 | ||||||
|
Interest payable
|
89,276 | 78,607 | ||||||
|
Due to joint venture partners
|
6,030 | 25,641 | ||||||
|
Warranty accrual
|
3,376 | 6,970 | ||||||
|
Litigation reserves
|
12,301 | 11,951 | ||||||
|
Professional fees
|
3,222 | 3,390 | ||||||
|
Current deferred tax liability
|
1,027 | 8,793 | ||||||
|
Other accrued liabilities
|
16,820 | 9,157 | ||||||
| $ | 394,292 | $ | 346,337 | |||||
117
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Investment income (loss) includes the following:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Interest and dividend income
|
$ | 7,162 | $ | 15,777 | $ | 40,148 | ||||||
|
Gains (losses) on marketable and non-marketable securities, net
|
486 | (1) | 9,822 | (2) | (18,736 | )(3) | ||||||
| $ | 7,648 | $ | 25,599 | $ | 21,412 | |||||||
| (1) | Reflects gain on sale of debt securities and gains from our long-term investments of $4.9 million, partially offset by net unrealized losses of $4.4 million from our trading securities. | |
| (2) | Reflects net unrealized gains of $9.8 million from our trading securities. | |
| (3) | Reflects net unrealized gains of $8.5 million from our trading securities, offset by losses of $27.4 million from our actively managed funds classified as long-term investments. |
Losses (gains) on sales and retirements of long-lived assets and
other expense (income), net includes the following:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Losses (gains) on sales, retirements and involuntary conversions
of long-lived assets
|
$ | 6,623 | $ | 5,525 | $ | 14,013 | (1) | |||||
|
Acquisition-related costs
|
7,021 | — | — | |||||||||
|
Litigation expenses
|
6,356 | 11,474 | 3,492 | |||||||||
|
Foreign currency transaction losses (gains)
|
17,878 | 8,372 | (2,718 | ) | ||||||||
|
Losses (gains) on derivative instruments
|
119 | (1,399 | ) | 14,581 | (2) | |||||||
|
Losses (gains) on debt extinguishment(3)
|
7,042 | (11,197 | ) | (12,248 | ) | |||||||
|
Other losses (gains)
|
2,021 | (216 | ) | (1,291 | ) | |||||||
| $ | 47,060 | $ | 12,559 | $ | 15,829 | |||||||
| (1) | Includes involuntary conversion losses recorded as a result of Hurricanes Gustav and Ike during 2008 of approximately $12.0 million, net of insurance recoveries. | |
| (2) | Includes a $9.9 million loss on a three-month written put option and a $4.7 million loss on the fair value of our range-cap-and-floor derivative. | |
| (3) | Includes $(7.0) million, $11.5 million and $12.2 million pre-tax (losses) gains on our purchases of our 0.94% senior exchangeable notes in the open market during 2010, 2009 and 2008, respectively. |
118
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Supplemental cash flow information for the years ended
December 31, 2010, 2009 and 2008 is as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Cash paid for income taxes
|
$ | 58,574 | $ | 107,994 | $ | 235,907 | ||||||
|
Cash paid for interest, net of capitalized interest
|
180,731 | 126,796 | 67,327 | |||||||||
|
Acquisitions of businesses:
|
||||||||||||
|
Fair value of assets acquired
|
796,399 | — | 7,328 | |||||||||
|
Goodwill
|
339,992 | — | 284 | |||||||||
|
Liabilities assumed
|
(332,528 | ) | — | (6,352 | ) | |||||||
|
Common stock of acquired company previously owned
|
— | — | — | |||||||||
|
Subsidiary preferred stock obligation
|
(69,188 | ) | — | — | ||||||||
|
Cash paid for acquisitions of businesses
|
734,675 | — | 1,260 | |||||||||
|
Cash acquired in acquisitions of businesses
|
(1,045 | ) | — | (973 | ) | |||||||
|
Cash paid for acquisitions of businesses, net
|
$ | 733,630 | $ | — | $ | 287 | ||||||
| Note 20 | Unaudited Quarterly Financial Information |
| Year Ended December 31, 2010 | ||||||||||||||||
| Quarter Ended | ||||||||||||||||
| March 31, | June 30, | September 30, | December 31, | |||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||
|
Operating revenues and Earnings (losses) from unconsolidated
affiliates from continuing operations(1)
|
$ | 898,988 | $ | 904,874 | $ | 1,081,103 | $ | 1,322,927 | ||||||||
|
Income (loss) from continuing operations, net of tax
|
$ | 43,519 | $ | 43,971 | $ | (31,563 | ) | $ | 50,183 | |||||||
|
Income from discontinued operations, net of tax
|
(4,421 | ) | (909 | ) | (7,591 | ) | 1,591 | |||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
1,102 | 559 | (453 | ) | (1,293 | ) | ||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 40,200 | $ | 43,621 | $ | (39,607 | ) | $ | 50,481 | |||||||
|
Earnings (loss) per share:(2)
|
||||||||||||||||
|
Basic from continuing operations
|
$ | .16 | $ | .15 | $ | (.11 | ) | $ | .18 | |||||||
|
Basic from discontinued operations
|
(.02 | ) | — | (.03 | ) | — | ||||||||||
|
Total Basic
|
$ | .14 | $ | .15 | $ | (.14 | ) | $ | .18 | |||||||
|
Diluted from continuing operations
|
$ | .16 | $ | .15 | $ | (.11 | ) | $ | .17 | |||||||
|
Diluted from discontinued operations
|
(.02 | ) | — | (.03 | ) | — | ||||||||||
|
Total Diluted
|
$ | .14 | $ | .15 | $ | (.14 | ) | $ | .17 | |||||||
119
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2009 | ||||||||||||||||
| Quarter Ended | ||||||||||||||||
| March 31, | June 30, | September 30, | December 31, | |||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||
|
Operating revenues and Earnings (losses) from unconsolidated
affiliates from continuing operations(3)
|
$ | 1,132,406 | $ | 862,103 | $ | 806,303 | $ | 727,174 | ||||||||
|
Income (loss) from continuing operations, net of tax
|
$ | 124,083 | $ | (184,565 | ) | $ | 53,675 | $ | (21,461 | ) | ||||||
|
Income from discontinued operations, net of tax
|
36 | (8,641 | ) | (23,250 | ) | (25,765 | ) | |||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
1,051 | 220 | (895 | ) | (34 | ) | ||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 125,170 | $ | (192,986 | ) | $ | 29,530 | $ | (47,260 | ) | ||||||
|
Earnings per share:(2)
|
||||||||||||||||
|
Basic from continuing operations
|
$ | .44 | $ | (.65 | ) | $ | .18 | $ | (.08 | ) | ||||||
|
Basic from discontinued operations
|
— | (.03 | ) | (.08 | ) | (.09 | ) | |||||||||
|
Total Basic
|
$ | .44 | $ | (.68 | ) | $ | .10 | $ | (.17 | ) | ||||||
|
Diluted from continuing operations
|
$ | .44 | $ | (.65 | ) | $ | .18 | $ | (.08 | ) | ||||||
|
Diluted from discontinued operations
|
— | (.03 | ) | (.08 | ) | (.09 | ) | |||||||||
|
Total Diluted
|
$ | .44 | $ | (.68 | ) | $ | .10 | $ | (.17 | ) | ||||||
| (1) | Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $7.6 million, $8.8 million, $11.8 million and $4.9 million, respectively. | |
| (2) | Earnings per share is computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year. | |
| (3) | Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $(64.5) million, $(5.7) million, $17.1 million and $(102.3) million, respectively. |
| Note 21 | Discontinued Operations |
During 2010, we began actively marketing our oil and gas assets
in the Horn River basin in Canada and in the Llanos basin in
Colombia. These assets include our 49.7% and 50.0% ownership
interests in our investments of Remora and SMVP, respectively,
which we account for using the equity method of accounting. All
of these assets are included in our oil and gas operating
segment. We determined that the plan of sale criteria in the ASC
Topic relating to the Presentation of Financial Statements for
Assets Sold or Held for Sale had been met during the third
quarter of 2010. Accordingly, we reclassified these wholly owned
oil and gas assets from our property, plant and equipment, net,
as well as our investment balances for Remora and SMVP from
investments in unconsolidated affiliates to assets held for sale
in our consolidated balance sheet at September 30, 2010.
The operating results from these assets for all periods
presented are reported as discontinued operations in the
accompanying audited consolidated statements of income (loss)
and the respective accompanying notes to
120
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
the consolidated financial statements. Our condensed statements
of income (loss) from discontinued operations for the years
ended December 31, 2010, 2009 and 2008 were as follows:
| Year Ended December 31, | ||||||||||||
| Condensed Statements of Income | 2010 | 2009 | 2008 | |||||||||
| (In thousands) | ||||||||||||
|
Revenues
|
$ | 37,840 | $ | 8,937 | $ | 4,354 | ||||||
|
Earnings (losses) from unconsolidated affiliates
(1)
|
$ | (10,628 | ) | $ | (59,248 | ) | $ | (37,286 | ) | |||
|
Income (loss) from discontinued operations
|
||||||||||||
|
Income (loss) from discontinued operations
|
$ | (13,195 | ) | $ | (73,045 | ) | $ | (45,443 | ) | |||
|
Less: income tax expense (benefit)
|
(1,865 | ) | (15,425 | ) | (3,513 | ) | ||||||
|
Income (loss) from discontinued operations, net of tax
|
$ | (11,330 | ) | $ | (57,620 | ) | $ | (41,930 | ) | |||
| (1) | Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million and $21.0 million for the years ended December 31, 2009 and 2008, respectively. |
| Note 22 | Segment Information |
As of December 31, 2010, we operated our business out of 11
operating segments. Our seven Contract Drilling operating
segments are engaged in drilling, workover and well-servicing
and pressure pumping operations, on land and offshore, and
represent reportable segments. These operating segments consist
of our Alaska, U.S. Lower 48 Land Drilling, U.S. Land
Well-servicing, Pressure Pumping, U.S. Offshore, Canada and
International business units. Our oil and gas operating segment
includes our wholly owned exploration entities and our
unconsolidated oil and gas joint ventures with First Reserve
Corporation. This segment is engaged in the exploration for, and
the development of and production of oil and natural gas. Our
Other Operating Segments, consisting of Canrig Drilling
Technology Ltd., Ryan Energy Technologies, and Nabors Blue Sky
Ltd., are engaged in the manufacturing of top drives,
manufacturing of drilling instrumentation systems, construction
and logistics services, trucking and logistics services,
manufacturing and marketing of directional drilling and rig
instrumentation systems, directional drilling, rig
instrumentation and data collection services, and heliportable
well services. These Other Operating Segments do not meet the
criteria for disclosure, individually or in the aggregate, as
reportable segments.
The accounting policies of the segments are the same as those
described in Note 2 — Summary of Significant
Accounting Policies. Inter-segment sales are recorded at cost or
cost plus a profit margin. We evaluate the performance of our
segments based on several criteria, including adjusted income
(loss) derived from operating activities.
121
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table sets forth financial information with
respect to our reportable segments:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Operating revenues and earnings (losses) from unconsolidated
affiliates from continuing operations:(1)
|
||||||||||||
|
Contract Drilling:(2)
|
||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 1,294,853 | $ | 1,082,531 | $ | 1,878,441 | ||||||
|
U.S. Land Well-servicing
|
444,665 | 412,243 | 758,510 | |||||||||
|
Pressure Pumping(3)
|
321,295 | — | — | |||||||||
|
U.S. Offshore
|
123,761 | 157,305 | 252,529 | |||||||||
|
Alaska
|
179,218 | 204,407 | 184,243 | |||||||||
|
Canada
|
389,229 | 298,653 | 502,695 | |||||||||
|
International
|
1,093,608 | 1,265,097 | 1,372,168 | |||||||||
|
Subtotal Contract Drilling(4)
|
3,846,629 | 3,420,236 | 4,948,586 | |||||||||
|
Oil and Gas(5)(6)
|
40,611 | (158,780 | ) | (118,533 | ) | |||||||
|
Other Operating Segments(7)(8)
|
456,893 | 446,282 | 683,186 | |||||||||
|
Other reconciling items(9)
|
(136,241 | ) | (179,752 | ) | (198,245 | ) | ||||||
|
Total
|
$ | 4,207,892 | $ | 3,527,986 | $ | 5,314,994 | ||||||
|
Depreciation and amortization, and depletion:(1)
|
||||||||||||
|
Contract Drilling:
|
||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 241,258 | $ | 226,875 | $ | 210,764 | ||||||
|
U.S. Land Well-servicing
|
65,561 | 69,557 | 65,050 | |||||||||
|
Pressure Pumping(3)
|
32,204 | — | — | |||||||||
|
U.S. Offshore
|
37,059 | 37,204 | 42,565 | |||||||||
|
Alaska
|
37,195 | 29,946 | 21,710 | |||||||||
|
Canada
|
74,735 | 65,883 | 67,373 | |||||||||
|
International
|
247,134 | 208,949 | 172,066 | |||||||||
|
Subtotal Contract Drilling
|
735,146 | 638,414 | 579,528 | |||||||||
|
Oil and Gas
|
19,988 | 9,476 | 22,308 | |||||||||
|
Other Operating Segments
|
31,880 | 30,542 | 38,903 | |||||||||
|
Other reconciling items(9)
|
(4,818 | ) | (1,915 | ) | (4,064 | ) | ||||||
|
Total depreciation and amortization, and depletion
|
$ | 782,196 | $ | 676,517 | $ | 636,675 | ||||||
|
Adjusted income (loss) derived from operating activities from
continuing operations:(1)(10)
|
||||||||||||
|
Contract Drilling:
|
||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 274,215 | $ | 294,679 | $ | 628,579 | ||||||
|
U.S. Land Well-servicing
|
31,597 | 28,950 | 148,626 | |||||||||
|
Pressure Pumping(3)
|
66,651 | — | — | |||||||||
|
U.S. Offshore
|
9,245 | 30,508 | 59,179 | |||||||||
|
Alaska
|
51,896 | 62,742 | 52,603 | |||||||||
|
Canada
|
22,970 | (7,019 | ) | 61,040 | ||||||||
|
International
|
254,744 | 365,566 | 407,675 | |||||||||
|
Subtotal Contract Drilling(4)
|
711,318 | 775,426 | 1,357,702 | |||||||||
|
Oil and Gas(5)(6)
|
6,329 | (190,798 | ) | (159,931 | ) | |||||||
|
Other Operating Segments(7)(8)
|
43,179 | 34,120 | 68,572 | |||||||||
|
Other reconciling items(11)
|
(105,393 | ) | (196,844 | ) | (167,831 | ) | ||||||
|
Total adjusted income derived from operating activities
|
$ | 655,433 | $ | 421,904 | $ | 1,098,512 | ||||||
122
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Interest expense
|
(273,044 | ) | (266,039 | ) | (196,718 | ) | ||||||
|
Investment income (loss)
|
7,648 | 25,599 | 21,412 | |||||||||
|
Gains (losses) on sales and retirements of long-lived assets and
other (income) expense, net
|
(47,060 | ) | (12,559 | ) | (15,829 | ) | ||||||
|
Impairments and other charges(12)
|
(260,931 | ) | (330,976 | ) | (176,123 | ) | ||||||
|
Income (loss) from continuing operations before income taxes
|
82,046 | (162,071 | ) | 731,254 | ||||||||
|
Income tax expense (benefit)
|
(24,814 | ) | (133,803 | ) | 209,660 | |||||||
|
Subsidiary preferred stock dividend
|
750 | — | — | |||||||||
|
Income (loss) from continuing operations, net of tax
|
106,110 | (28,268 | ) | 521,594 | ||||||||
|
Income (loss) from discontinued operations, net of tax
|
(11,330 | ) | (57,620 | ) | (41,930 | ) | ||||||
|
Net income (loss)
|
94,780 | (85,888 | ) | 479,664 | ||||||||
|
Less: Net income (loss) attributable to noncontrolling interest
|
(85 | ) | 342 | (3,927 | ) | |||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | $ | (85,546 | ) | $ | 475,737 | |||||
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Capital expenditures and acquisitions of businesses:(13)
|
||||||||||||
|
Contract Drilling:
|
||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 294,239 | $ | 327,269 | $ | 405,831 | ||||||
|
U.S. Land Well-servicing
|
84,657 | 16,671 | 48,911 | |||||||||
|
Pressure Pumping(3)
|
924,693 | — | — | |||||||||
|
U.S. Offshore
|
23,625 | 48,694 | 82,574 | |||||||||
|
Alaska
|
891 | 55,426 | 85,735 | |||||||||
|
Canada
|
53,834 | 29,214 | 85,113 | |||||||||
|
International
|
365,597 | 328,252 | 635,340 | |||||||||
|
Subtotal Contract Drilling
|
1,747,536 | 805,526 | 1,343,504 | |||||||||
|
Oil and Gas
|
113,361 | 184,185 | 191,937 | |||||||||
|
Other Operating Segments
|
28,799 | 20,446 | 32,191 | |||||||||
|
Other reconciling items(11)(17)
|
(11,633 | ) | (19,870 | ) | 10,609 | |||||||
|
Total capital expenditures and acquisitions of businesses
|
$ | 1,878,063 | $ | 990,287 | $ | 1,578,241 | ||||||
123
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Total assets:
|
||||||||||||
|
Contract Drilling:(14)
|
||||||||||||
|
U.S. Lower 48 Land Drilling
|
$ | 2,762,362 | $ | 2,609,101 | $ | 2,833,618 | ||||||
|
U.S. Land Well-servicing
|
630,518 | 594,456 | 707,009 | |||||||||
|
Pressure Pumping(3)
|
1,163,236 | — | — | |||||||||
|
U.S. Offshore
|
379,292 | 440,556 | 480,324 | |||||||||
|
Alaska
|
313,123 | 373,146 | 356,603 | |||||||||
|
Canada
|
1,065,268 | 984,740 | 906,154 | |||||||||
|
International
|
3,279,763 | 3,151,513 | 3,080,947 | |||||||||
|
Subtotal Contract Drilling
|
9,593,562 | 8,153,512 | 8,364,655 | |||||||||
|
Oil and Gas(15)
|
805,410 | 835,465 | 929,848 | |||||||||
|
Other Operating Segments(16)
|
539,373 | 502,501 | 578,802 | |||||||||
|
Other reconciling items(11)(17)
|
708,224 | 1,153,212 | 644,594 | |||||||||
|
Total assets
|
$ | 11,646,569 | $ | 10,644,690 | $ | 10,517,899 | ||||||
| (1) | All information presents the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia as discontinued operations. | |
| (2) | These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore. | |
| (3) | Includes operating results of the Superior Merger after September 10, 2010. | |
| (4) | Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $6.9 million, $9.7 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (5) | Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(189.3) million and $(207.3) million for the years ended December 31, 2009 and 2008, respectively. | |
| (6) | Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $18.7 million, $(182.6) million and $(204.1) million for the years ended December 31, 2010, 2009 and 2008, respectively. Additional information is provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities. | |
| (7) | Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations. | |
| (8) | Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $7.7 million, $17.5 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (9) | Represents the elimination of inter-segment transactions. | |
| (10) | Adjusted income (loss) derived from operating activities is computed by subtracting direct costs, general and administrative expenses, depreciation and amortization, and depletion expense from Operating revenues and then adding Earnings (losses) from unconsolidated affiliates. Such amounts should not be used as a substitute for those amounts reported under GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income |
124
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (loss) derived from operating activities, because it believes that these financial measures are an accurate reflection of the ongoing profitability of our Company. A reconciliation of this non-GAAP measure to income (loss) before income taxes, which is a GAAP measure, is provided within the above table. | ||
| (11) | Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures. | |
| (12) | Represents impairments and other charges recorded during the years ended December 31, 2010, 2009 and 2008, respectively. | |
| (13) | Includes the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value. | |
| (14) | Includes $54.8 million, $49.8 million and $49.2 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2010, 2009 and 2008, respectively. | |
| (15) | Includes $146.5 million, $190.1 million and $298.3 million investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2010, 2009 and 2008, respectively. | |
| (16) | Includes $64.5 million, $65.8 million and $63.3 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2010, 2009 and 2008, respectively. | |
| (17) | Includes $1.9 million and $.9 million of investments in unconsolidated affiliates accounted for using the cost method as of December 31, 2010 and 2009, respectively. |
The following table sets forth financial information with
respect to Nabors’ operations by geographic area:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Operating revenues and earnings (losses) from unconsolidated
affiliates from continuing operations:
|
||||||||||||
|
U.S.
|
$ | 2,633,055 | $ | 1,802,140 | $ | 3,306,064 | ||||||
|
Outside the U.S.
|
1,574,837 | 1,725,846 | 2,008,930 | |||||||||
| $ | 4,207,892 | $ | 3,527,986 | $ | 5,314,994 | |||||||
|
Property, plant and equipment, net:
|
||||||||||||
|
U.S.
|
$ | 4,447,388 | $ | 4,107,250 | $ | 4,059,697 | ||||||
|
Outside the U.S.
|
3,368,031 | 3,538,800 | 3,272,262 | |||||||||
| $ | 7,815,419 | $ | 7,646,050 | $ | 7,331,959 | |||||||
|
Goodwill:
|
||||||||||||
|
U.S.
|
$ | 459,560 | $ | 130,275 | $ | 130,275 | ||||||
|
Outside the U.S.
|
34,812 | 33,990 | 45,474 | |||||||||
| $ | 494,372 | $ | 164,265 | $ | 175,749 | |||||||
| Note 23 | Condensed Consolidating Financial Information |
Nabors has fully and unconditionally guaranteed all of the
issued public debt securities of Nabors Delaware, and Nabors and
Nabors Delaware fully and unconditionally guaranteed the
4.875% senior notes due August 2009 issued by Nabors
Holdings 1, ULC, an unlimited liability company formed under the
Companies Act of Nova Scotia, Canada and a subsidiary of Nabors
(“Nabors Holdings”). During 2009, we paid the balance
of Nabors Holdings 1, ULC’s 4.875% senior notes.
Effective September 30, 2009, Nabors Holdings 1, ULC was
amalgamated with Nabors Drilling Canada ULC, the successor
company.
125
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following condensed consolidating financial information is
included so that separate financial statements of Nabors
Delaware and Nabors Holdings are not required to be filed with
the SEC. The condensed consolidating financial statements
present investments in both consolidated and unconsolidated
affiliates using the equity method of accounting.
The following condensed consolidating financial information
presents condensed consolidating balance sheets as of
December 31, 2010 and 2009, statements of income (loss) for
the years ended December 31, 2010, 2009 and 2008 and the
consolidating statements of cash flows for the years ended
December 31, 2010, 2009 and 2008 of (a) Nabors,
parent/guarantor, (b) Nabors Delaware, issuer of public
debt securities guaranteed by Nabors and guarantor of the
4.875% senior notes issued by Nabors Holdings,
(c) Nabors Holdings, issuer of the 4.875% senior
notes, (d) the non-guarantor subsidiaries,
(e) consolidating adjustments necessary to consolidate
Nabors and its subsidiaries and (f) Nabors on a
consolidated basis.
126
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Condensed
Consolidating Balance Sheets
| December 31, 2010 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non-
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||||||
|
Current assets:
|
||||||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 10,847 | $ | 20 | $ | — | $ | 630,835 | $ | — | $ | 641,702 | ||||||||||||
|
Short-term investments
|
— | — | — | 159,488 | — | 159,488 | ||||||||||||||||||
|
Assets held for sale
|
— | — | — | 352,048 | — | 352,048 | ||||||||||||||||||
|
Accounts receivable, net
|
— | — | — | 1,116,510 | — | 1,116,510 | ||||||||||||||||||
|
Inventory
|
— | — | — | 158,836 | — | 158,836 | ||||||||||||||||||
|
Deferred income taxes
|
— | — | — | 31,510 | — | 31,510 | ||||||||||||||||||
|
Other current assets
|
50 | 16,366 | — | 136,420 | — | 152,836 | ||||||||||||||||||
|
Total current assets
|
10,897 | 16,386 | — | 2,585,647 | — | 2,612,930 | ||||||||||||||||||
|
Long-term investments and other receivables
|
— | — | — | 40,300 | — | 40,300 | ||||||||||||||||||
|
Property, plant and equipment, net
|
— | 44,270 | — | 7,771,149 | — | 7,815,419 | ||||||||||||||||||
|
Goodwill
|
— | — | — | 494,372 | — | 494,372 | ||||||||||||||||||
|
Intercompany receivables
|
160,250 | — | — | 322,697 | (482,947 | ) | — | |||||||||||||||||
|
Investment in unconsolidated affiliates
|
5,160,800 | 5,814,219 | — | 1,665,459 | (12,372,755 | ) | 267,723 | |||||||||||||||||
|
Other long-term assets
|
— | 36,538 | — | 379,287 | — | 415,825 | ||||||||||||||||||
|
Total assets
|
$ | 5,331,947 | $ | 5,911,413 | $ | — | $ | 13,258,911 | $ | (12,855,702 | ) | $ | 11,646,569 | |||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||||||||||||
|
Current liabilities:
|
||||||||||||||||||||||||
|
Current portion of
long-term
debt
|
$ | — | $ | 1,378,178 | $ | — | $ | 840 | $ | — | $ | 1,379,018 | ||||||||||||
|
Trade accounts payable
|
— | — | — | 355,282 | — | 355,282 | ||||||||||||||||||
|
Accrued liabilities
|
3,785 | 89,480 | — | 301,027 | — | 394,292 | ||||||||||||||||||
|
Income taxes payable
|
— | 6,859 | — | 18,929 | — | 25,788 | ||||||||||||||||||
|
Total current liabilities
|
3,785 | 1,474,517 | — | 676,078 | — | 2,154,380 | ||||||||||||||||||
|
Long-term debt
|
— | 3,062,291 | — | 1,835 | — | 3,064,126 | ||||||||||||||||||
|
Other long-term liabilities
|
— | 12,787 | — | 232,978 | — | 245,765 | ||||||||||||||||||
|
Deferred income taxes
|
— | 71,815 | — | 698,432 | — | 770,247 | ||||||||||||||||||
|
Intercompany payable
|
— | 301,451 | — | 181,496 | (482,947 | ) | — | |||||||||||||||||
|
Total liabilities
|
3,785 | 4,922,861 | — | 1,790,819 | (482,947 | ) | 6,234,518 | |||||||||||||||||
|
Subsidiary preferred stock
|
— | — | — | 69,188 | — | 69,188 | ||||||||||||||||||
|
Shareholders’ equity
|
5,328,162 | 988,552 | — | 11,384,203 | (12,372,755 | ) | 5,328,162 | |||||||||||||||||
|
Noncontrolling interest
|
— | — | — | 14,701 | — | 14,701 | ||||||||||||||||||
|
Total equity
|
5,328,162 | 988,552 | — | 11,398,904 | (12,372,755 | ) | 5,342,863 | |||||||||||||||||
|
Total liabilities and equity
|
$ | 5,331,947 | $ | 5,911,413 | $ | — | $ | 13,258,911 | $ | (12,855,702 | ) | $ | 11,646,569 | |||||||||||
127
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| December 31, 2009 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non-
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||||||
|
Current assets:
|
||||||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 11,702 | $ | 135 | $ | — | $ | 915,978 | $ | — | $ | 927,815 | ||||||||||||
|
Short-term investments
|
— | — | — | 163,036 | — | 163,036 | ||||||||||||||||||
|
Accounts receivable, net
|
— | — | — | 724,040 | — | 724,040 | ||||||||||||||||||
|
Inventory
|
— | — | — | 100,819 | — | 100,819 | ||||||||||||||||||
|
Deferred income taxes
|
— | — | — | 125,163 | — | 125,163 | ||||||||||||||||||
|
Other current assets
|
50 | (15,606 | ) | — | 151,347 | — | 135,791 | |||||||||||||||||
|
Total current assets
|
11,752 | (15,471 | ) | — | 2,180,383 | — | 2,176,664 | |||||||||||||||||
|
Long-term investments and other receivables
|
— | — | — | 100,882 | — | 100,882 | ||||||||||||||||||
|
Property, plant and equipment, net
|
— | 46,473 | — | 7,599,577 | — | 7,646,050 | ||||||||||||||||||
|
Goodwill
|
— | — | — | 164,265 | — | 164,265 | ||||||||||||||||||
|
Intercompany receivables
|
233,482 | 453,298 | — | 192,492 | (879,272 | ) | — | |||||||||||||||||
|
Investment in unconsolidated affiliates
|
4,923,949 | 5,110,430 | — | 2,168,884 | (11,896,655 | ) | 306,608 | |||||||||||||||||
|
Other long-term assets
|
— | 29,952 | — | 220,269 | — | 250,221 | ||||||||||||||||||
|
Total assets
|
$ | 5,169,183 | $ | 5,624,682 | $ | — | $ | 12,626,752 | $ | (12,775,927 | ) | $ | 10,644,690 | |||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||||||||||||
|
Current liabilities:
|
||||||||||||||||||||||||
|
Current portion of long-term debt
|
$ | — | $ | — | $ | — | $ | 163 | $ | — | $ | 163 | ||||||||||||
|
Trade accounts payable
|
20 | 8 | — | 226,395 | — | 226,423 | ||||||||||||||||||
|
Accrued liabilities
|
1,507 | 78,359 | — | 266,471 | — | 346,337 | ||||||||||||||||||
|
Income taxes payable
|
— | 9,530 | — | 26,169 | — | 35,699 | ||||||||||||||||||
|
Total current liabilities
|
1,527 | 87,897 | — | 519,198 | — | 608,622 | ||||||||||||||||||
|
Long-term debt
|
— | 3,939,896 | — | 709 | — | 3,940,605 | ||||||||||||||||||
|
Other long-term liabilities
|
— | 3,446 | — | 236,611 | — | 240,057 | ||||||||||||||||||
|
Deferred income taxes
|
— | 112,760 | — | 560,667 | — | 673,427 | ||||||||||||||||||
|
Intercompany payable
|
— | — | — | 879,272 | (879,272 | ) | — | |||||||||||||||||
|
Total liabilities
|
1,527 | 4,143,999 | — | 2,196,457 | (879,272 | ) | 5,462,711 | |||||||||||||||||
|
Shareholders’ equity
|
5,167,656 | 1,480,683 | — | 10,415,972 | (11,896,655 | ) | 5,167,656 | |||||||||||||||||
|
Noncontrolling interest
|
— | — | — | 14,323 | — | 14,323 | ||||||||||||||||||
|
Total equity
|
5,167,656 | 1,480,683 | — | 10,430,295 | (11,896,655 | ) | 5,181,979 | |||||||||||||||||
|
Total liabilities and equity
|
$ | 5,169,183 | $ | 5,624,682 | $ | — | $ | 12,626,752 | $ | (12,775,927 | ) | $ | 10,644,690 | |||||||||||
128
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Condensed
Consolidating Statements of Income (Loss)
| Year Ended December 31, 2010 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Revenues and other income:
|
||||||||||||||||||||||||
|
Operating revenues
|
$ | — | $ | — | $ | — | $ | 4,174,635 | $ | — | $ | 4,174,635 | ||||||||||||
|
Earnings (losses) from unconsolidated affiliates
|
— | — | — | 33,257 | — | 33,257 | ||||||||||||||||||
|
Earnings (losses) from consolidated affiliates
|
68,749 | (183,242 | ) | — | (316,657 | ) | 431,150 | — | ||||||||||||||||
|
Investment income (loss)
|
15 | — | — | 7,633 | — | 7,648 | ||||||||||||||||||
|
Intercompany interest income
|
— | 72,435 | — | — | (72,435 | ) | — | |||||||||||||||||
|
Total revenues and other income
|
68,764 | (110,807 | ) | — | 3,898,868 | 358,715 | 4,215,540 | |||||||||||||||||
|
Costs and other deductions:
|
||||||||||||||||||||||||
|
Direct costs
|
— | — | — | 2,423,602 | — | 2,423,602 | ||||||||||||||||||
|
General and administrative expenses
|
9,165 | 445 | — | 338,008 | (957 | ) | 346,661 | |||||||||||||||||
|
Depreciation and amortization
|
— | 3,303 | — | 760,950 | — | 764,253 | ||||||||||||||||||
|
Depletion
|
— | — | — | 17,943 | — | 17,943 | ||||||||||||||||||
|
Interest expense
|
— | 283,396 | — | (10,352 | ) | — | 273,044 | |||||||||||||||||
|
Intercompany interest expense
|
— | — | — | 72,435 | (72,435 | ) | — | |||||||||||||||||
|
Losses (gains) on sales and retirements of long-lived assets and
other expense (income), net
|
(35,096 | ) | 42,504 | — | 38,695 | 957 | 47,060 | |||||||||||||||||
|
Impairments and other charges
|
— | — | — | 260,931 | — | 260,931 | ||||||||||||||||||
|
Total costs and other deductions
|
(25,931 | ) | 329,648 | — | 3,902,212 | (72,435 | ) | 4,133,494 | ||||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
94,695 | (440,455 | ) | — | (3,344 | ) | 431,150 | 82,046 | ||||||||||||||||
|
Income tax expense (benefit)
|
— | (95,168 | ) | — | 70,354 | — | (24,814 | ) | ||||||||||||||||
|
Subsidiary preferred stock dividend
|
— | — | — | 750 | — | 750 | ||||||||||||||||||
|
Income (loss) from continuing operations, net of tax
|
94,695 | (345,287 | ) | — | (74,448 | ) | 431,150 | 106,110 | ||||||||||||||||
|
Income (loss) from discontinued operations, net of tax
|
— | — | — | (11,330 | ) | — | (11,330 | ) | ||||||||||||||||
|
Net income (loss)
|
94,695 | (345,287 | ) | — | (85,778 | ) | 431,150 | 94,780 | ||||||||||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
— | — | — | (85 | ) | — | (85 | ) | ||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 94,695 | $ | (345,287 | ) | $ | — | $ | (85,863 | ) | $ | 431,150 | $ | 94,695 | ||||||||||
129
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2009 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Revenues and other income:
|
||||||||||||||||||||||||
|
Operating revenues
|
$ | — | $ | — | $ | — | $ | 3,683,419 | $ | — | $ | 3,683,419 | ||||||||||||
|
Earnings (losses) from unconsolidated affiliates
|
— | — | — | (155,433 | ) | — | (155,433 | ) | ||||||||||||||||
|
Earnings (losses) from consolidated affiliates
|
(74,204 | ) | (316,443 | ) | (86,751 | ) | (441,133 | ) | 918,531 | — | ||||||||||||||
|
Investment income (loss)
|
58 | 2,357 | 101 | 23,083 | — | 25,599 | ||||||||||||||||||
|
Intercompany interest income
|
— | 66,150 | 5,558 | — | (71,708 | ) | — | |||||||||||||||||
|
Total revenues and other income
|
(74,146 | ) | (247,936 | ) | (81,092 | ) | 3,109,936 | 846,823 | 3,553,585 | |||||||||||||||
|
Costs and other deductions:
|
||||||||||||||||||||||||
|
Direct costs
|
— | — | — | 2,001,404 | — | 2,001,404 | ||||||||||||||||||
|
General and administrative expenses
|
28,350 | 336 | 1 | 400,044 | (570 | ) | 428,161 | |||||||||||||||||
|
Depreciation and amortization
|
— | 3,594 | — | 663,506 | — | 667,100 | ||||||||||||||||||
|
Depletion
|
— | — | — | 9,417 | — | 9,417 | ||||||||||||||||||
|
Interest expense
|
— | 288,715 | 5,634 | (28,310 | ) | — | 266,039 | |||||||||||||||||
|
Intercompany interest expense
|
— | — | — | 71,708 | (71,708 | ) | — | |||||||||||||||||
|
Losses (gains) on sales and retirements of long-lived assets and
other expense (income), net
|
(16,950 | ) | 4,145 | 5,069 | 37,972 | (17,677 | ) | 12,559 | ||||||||||||||||
|
Impairments and other charges
|
— | — | — | 330,976 | — | 330,976 | ||||||||||||||||||
|
Total costs and other deductions
|
11,400 | 296,790 | 10,704 | 3,486,717 | (89,955 | ) | 3,715,656 | |||||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
(85,546 | ) | (544,726 | ) | (91,796 | ) | (376,781 | ) | 936,778 | (162,071 | ) | |||||||||||||
|
Income tax expense (benefit)
|
— | (84,465 | ) | 15,744 | (65,082 | ) | — | (133,803 | ) | |||||||||||||||
|
Income (loss) from continuing operations, net of tax
|
(85,546 | ) | (460,261 | ) | (107,540 | ) | (311,699 | ) | 936,778 | (28,268 | ) | |||||||||||||
|
Income (loss) from discontinued operations, net of tax
|
— | — | — | (57,620 | ) | — | (57,620 | ) | ||||||||||||||||
|
Net income (loss)
|
(85,546 | ) | (460,261 | ) | (107,540 | ) | (369,319 | ) | 936,778 | (85,888 | ) | |||||||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
— | — | — | 342 | — | 342 | ||||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | (85,546 | ) | $ | (460,261 | ) | $ | (107,540 | ) | $ | (368,977 | ) | $ | 936,778 | $ | (85,546 | ) | |||||||
130
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2008 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Revenues and other income:
|
||||||||||||||||||||||||
|
Operating revenues
|
$ | — | $ | — | $ | — | $ | 5,507,542 | $ | — | $ | 5,507,542 | ||||||||||||
|
Earnings (losses) from unconsolidated affiliates
|
— | — | — | (192,548 | ) | — | (192,548 | ) | ||||||||||||||||
|
Earnings (losses) from consolidated affiliates
|
490,138 | 197,934 | 19,335 | 130,981 | (838,388 | ) | — | |||||||||||||||||
|
Investment income (loss)
|
364 | 2,373 | 3 | 18,672 | — | 21,412 | ||||||||||||||||||
|
Intercompany interest income
|
4,000 | 70,017 | 11,840 | — | (85,857 | ) | — | |||||||||||||||||
|
Total revenues and other income
|
494,502 | 270,324 | 31,178 | 5,464,647 | (924,245 | ) | 5,336,406 | |||||||||||||||||
|
Costs and other deductions:
|
||||||||||||||||||||||||
|
Direct costs
|
— | — | — | 3,100,613 | — | 3,100,613 | ||||||||||||||||||
|
General and administrative expenses
|
21,191 | 494 | 32 | 458,792 | (1,315 | ) | 479,194 | |||||||||||||||||
|
Depreciation and amortization
|
— | 3,901 | — | 610,466 | — | 614,367 | ||||||||||||||||||
|
Depletion
|
— | — | — | 22,308 | — | 22,308 | ||||||||||||||||||
|
Interest expense
|
— | 197,145 | 11,440 | (11,867 | ) | — | 196,718 | |||||||||||||||||
|
Intercompany interest expense
|
— | — | — | 85,857 | (85,857 | ) | — | |||||||||||||||||
|
Losses (gains) on sales and retirements of long-lived assets and
other expense (income), net
|
(2,426 | ) | (5,045 | ) | 27,444 | (5,459 | ) | 1,315 | 15,829 | |||||||||||||||
|
Impairments and other charges
|
— | — | — | 176,123 | — | 176,123 | ||||||||||||||||||
|
Total costs and other deductions
|
18,765 | 196,495 | 38,916 | 4,436,833 | (85,857 | ) | 4,605,152 | |||||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
475,737 | 73,829 | (7,738 | ) | 1,027,814 | (838,388 | ) | 731,254 | ||||||||||||||||
|
Income tax expense (benefit)
|
— | (45,920 | ) | (2,477 | ) | 258,057 | — | 209,660 | ||||||||||||||||
|
Income (loss) from continuing operations, net of tax
|
475,737 | 119,749 | (5,261 | ) | 769,757 | (838,388 | ) | 521,594 | ||||||||||||||||
|
Income (loss) from discontinued operations, net of tax
|
— | — | — | (41,930 | ) | — | (41,930 | ) | ||||||||||||||||
|
Net income (loss)
|
475,737 | 119,749 | (5,261 | ) | 727,827 | (838,388 | ) | 479,664 | ||||||||||||||||
|
Less: Net (income) loss attributable to noncontrolling interest
|
— | — | — | (3,927 | ) | — | (3,927 | ) | ||||||||||||||||
|
Net income (loss) attributable to Nabors
|
$ | 475,737 | $ | 119,749 | $ | (5,261 | ) | $ | 723,900 | $ | (838,388 | ) | $ | 475,737 | ||||||||||
131
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Condensed
Consolidating Statements of Cash Flows
| Year Ended December 31, 2010 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Net cash provided by (used for) operating activities
|
$ | 115,179 | $ | 757,345 | $ | — | $ | 504,460 | $ | (270,000 | ) | $ | 1,106,984 | |||||||||||
|
Cash flows from investing activities:
|
||||||||||||||||||||||||
|
Purchases of investments
|
— | — | — | (34,147 | ) | — | (34,147 | ) | ||||||||||||||||
|
Sales and maturities of investments
|
— | — | — | 34,613 | — | 34,613 | ||||||||||||||||||
|
Cash paid for acquisition of businesses, net
|
— | — | — | (733,630 | ) | — | (733,630 | ) | ||||||||||||||||
|
Investment in unconsolidated affiliates
|
— | — | — | (40,936 | ) | — | (40,936 | ) | ||||||||||||||||
|
Capital expenditures
|
— | — | — | (930,277 | ) | — | (930,277 | ) | ||||||||||||||||
|
Proceeds from sales of assets and insurance claims
|
— | — | — | 31,072 | — | 31,072 | ||||||||||||||||||
|
Cash paid for investments in consolidated affiliates
|
(122,300 | ) | (1,027,134 | ) | — | — | 1,149,434 | — | ||||||||||||||||
|
Net cash provided by (used for) investing activities
|
(122,300 | ) | (1,027,134 | ) | — | (1,673,305 | ) | 1,149,434 | (1,673,305 | ) | ||||||||||||||
|
Cash flows from financing activities:
|
||||||||||||||||||||||||
|
Increase (decrease) in cash overdrafts
|
— | — | — | (6,298 | ) | — | (6,298 | ) | ||||||||||||||||
|
Proceeds from long-term debt
|
— | 696,948 | — | — | — | 696,948 | ||||||||||||||||||
|
Debt issuance costs
|
— | (8,934 | ) | — | — | — | (8,934 | ) | ||||||||||||||||
|
Payments for hedge transactions
|
— | (5,667 | ) | — | — | — | (5,667 | ) | ||||||||||||||||
|
Proceeds from Revolving Credit Facility
|
— | 600,000 | — | — | — | 600,000 | ||||||||||||||||||
|
Intercompany debt
|
— | — | — | — | — | — | ||||||||||||||||||
|
Proceeds from issuance of common shares
|
8,201 | — | — | — | — | 8,201 | ||||||||||||||||||
|
Reduction in long-term debt
|
— | (274,095 | ) | — | (124,419 | ) | — | (398,514 | ) | |||||||||||||||
|
Reduction in Revolving Credit Facility
|
— | (600,000 | ) | — | — | — | (600,000 | ) | ||||||||||||||||
|
Repurchase of equity component of convertible debt
|
— | (4,712 | ) | — | — | — | (4,712 | ) | ||||||||||||||||
|
Settlement of call options and warrants, net
|
— | 1,134 | — | — | — | 1,134 | ||||||||||||||||||
|
Purchase of restricted stock
|
(1,935 | ) | — | — | — | — | (1,935 | ) | ||||||||||||||||
|
Tax benefit related to share-based awards
|
— | — | — | 31 | — | 31 | ||||||||||||||||||
|
Cash dividends paid
|
— | (135,000 | ) | — | (135,000 | ) | 270,000 | — | ||||||||||||||||
|
Proceeds from parent contributions
|
— | — | — | 1,149,434 | (1,149,434 | ) | — | |||||||||||||||||
|
Net cash (used for) provided by financing activities
|
6,266 | 269,674 | — | 883,748 | (879,434 | ) | 280,254 | |||||||||||||||||
|
Effect of exchange rate changes on cash and cash equivalents
|
— | — | — | (46 | ) | — | (46 | ) | ||||||||||||||||
|
Net (decrease) increase in cash and cash equivalents
|
(855 | ) | (115 | ) | — | (285,143 | ) | — | (286,113 | ) | ||||||||||||||
|
Cash and cash equivalents, beginning of period
|
11,702 | 135 | — | 915,978 | — | 927,815 | ||||||||||||||||||
|
Cash and cash equivalents, end of period
|
$ | 10,847 | $ | 20 | $ | — | $ | 630,835 | $ | — | $ | 641,702 | ||||||||||||
132
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2009 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Net cash provided by (used for) operating activities
|
$ | 40,589 | $ | 646,645 | $ | 608 | $ | 1,089,086 | $ | (159,956 | ) | $ | 1,616,972 | |||||||||||
|
Cash flows from investing activities:
|
||||||||||||||||||||||||
|
Purchases of investments
|
— | — | — | (32,674 | ) | — | (32,674 | ) | ||||||||||||||||
|
Sales and maturities of investments
|
— | — | — | 57,033 | — | 57,033 | ||||||||||||||||||
|
Investment in unconsolidated affiliates
|
— | — | — | (125,076 | ) | — | (125,076 | ) | ||||||||||||||||
|
Capital expenditures
|
— | — | — | (1,093,435 | ) | — | (1,093,435 | ) | ||||||||||||||||
|
Proceeds from sales of assets and insurance claims
|
— | — | — | 31,375 | — | 31,375 | ||||||||||||||||||
|
Proceeds from sale of consolidated affiliates
|
— | — | 239,421 | (239,421 | ) | — | — | |||||||||||||||||
|
Cash paid for investments in consolidated affiliates
|
(46,912 | ) | (900,000 | ) | — | — | 946,912 | — | ||||||||||||||||
|
Net cash provided by (used for) investing activities
|
(46,912 | ) | (900,000 | ) | 239,421 | (1,402,198 | ) | 946,912 | (1,162,777 | ) | ||||||||||||||
|
Cash flows from financing activities:
|
||||||||||||||||||||||||
|
Increase (decrease) in cash overdrafts
|
— | — | — | (18,157 | ) | — | (18,157 | ) | ||||||||||||||||
|
Proceeds from long-term debt
|
— | 1,124,978 | — | — | — | 1,124,978 | ||||||||||||||||||
|
Debt issuance costs
|
— | (8,832 | ) | — | — | — | (8,832 | ) | ||||||||||||||||
|
Intercompany debt
|
— | — | 143,859 | (143,859 | ) | — | — | |||||||||||||||||
|
Proceeds from issuance of common shares
|
11,249 | — | — | — | — | 11,249 | ||||||||||||||||||
|
Reduction in long-term debt
|
— | (856,203 | ) | (225,191 | ) | (407 | ) | — | (1,081,801 | ) | ||||||||||||||
|
Repurchase of equity component of convertible debt
|
— | (6,586 | ) | — | — | — | (6,586 | ) | ||||||||||||||||
|
Purchase of restricted stock
|
(1,515 | ) | — | — | — | — | (1,515 | ) | ||||||||||||||||
|
Tax benefit related to share-based awards
|
— | 37 | — | — | — | 37 | ||||||||||||||||||
|
Cash dividends paid
|
— | — | (159,956 | ) | — | 159,956 | — | |||||||||||||||||
|
Proceeds from parent contributions
|
— | — | — | 946,912 | (946,912 | ) | — | |||||||||||||||||
|
Net cash (used for) provided by financing activities
|
9,734 | 253,394 | (241,288 | ) | 784,489 | (786,956 | ) | 19,373 | ||||||||||||||||
|
Effect of exchange rate changes on cash and cash equivalents
|
— | — | — | 12,160 | — | 12,160 | ||||||||||||||||||
|
Net (decrease) increase in cash and cash equivalents
|
3,411 | 39 | (1,259 | ) | 483,537 | — | 485,728 | |||||||||||||||||
|
Cash and cash equivalents, beginning of period
|
8,291 | 96 | 1,259 | 432,441 | — | 442,087 | ||||||||||||||||||
|
Cash and cash equivalents, end of period
|
$ | 11,702 | $ | 135 | $ | — | $ | 915,978 | $ | — | $ | 927,815 | ||||||||||||
133
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2008 | ||||||||||||||||||||||||
|
Nabors
|
Other
|
|||||||||||||||||||||||
|
Nabors
|
Delaware
|
Nabors
|
Subsidiaries
|
|||||||||||||||||||||
|
(Parent/
|
(Issuer/
|
Holdings
|
(Non
|
Consolidating
|
Consolidated
|
|||||||||||||||||||
| Guarantor) | Guarantor) | (Issuer) | Guarantors) | Adjustments | Total | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Net cash provided by (used for) operating activities
|
$ | 39,987 | $ | 287,628 | $ | (162,293 | ) | $ | 1,455,628 | $ | (158,126 | ) | $ | 1,462,824 | ||||||||||
|
Cash flows from investing activities:
|
||||||||||||||||||||||||
|
Purchases of investments
|
— | — | — | (269,983 | ) | — | (269,983 | ) | ||||||||||||||||
|
Sales and maturities of investments
|
— | — | — | 521,613 | — | 521,613 | ||||||||||||||||||
|
Cash paid for acquisitions of businesses, net
|
— | — | — | (287 | ) | — | (287 | ) | ||||||||||||||||
|
Investment in unconsolidated affiliates
|
— | — | — | (271,309 | ) | — | (271,309 | ) | ||||||||||||||||
|
Capital expenditures
|
— | (16,817 | ) | — | (1,490,162 | ) | — | (1,506,979 | ) | |||||||||||||||
|
Proceeds from sales of assets and insurance claims
|
— | — | — | 69,842 | — | 69,842 | ||||||||||||||||||
|
Cash paid for investments in consolidated affiliates
|
(85,927 | ) | (150,626 | ) | — | (163,548 | ) | 400,101 | — | |||||||||||||||
|
Net cash provided by (used for) investing activities
|
(85,927 | ) | (167,443 | ) | — | (1,603,834 | ) | 400,101 | (1,457,103 | ) | ||||||||||||||
|
Cash flows from financing activities:
|
||||||||||||||||||||||||
|
Increase (decrease) in cash overdrafts
|
— | — | — | 23,858 | — | 23,858 | ||||||||||||||||||
|
Proceeds from long-term debt
|
— | 962,901 | — | — | — | 962,901 | ||||||||||||||||||
|
Debt issuance costs
|
— | (7,324 | ) | — | — | — | (7,324 | ) | ||||||||||||||||
|
Proceeds from issuance of common shares
|
56,633 | — | — | (3 | ) | — | 56,630 | |||||||||||||||||
|
Reduction in long-term debt
|
— | (836,431 | ) | — | (80 | ) | — | (836,511 | ) | |||||||||||||||
|
Repurchase of common shares
|
— | (247,357 | ) | — | (33,744 | ) | — | (281,101 | ) | |||||||||||||||
|
Purchase of restricted stock
|
(13,061 | ) | — | — | — | — | (13,061 | ) | ||||||||||||||||
|
Tax benefit related to share-based awards
|
— | 5,369 | — | — | — | 5,369 | ||||||||||||||||||
|
Cash dividends paid
|
— | — | — | (158,126 | ) | 158,126 | — | |||||||||||||||||
|
Proceeds from parent contributions
|
— | — | 163,548 | 236,553 | (400,101 | ) | — | |||||||||||||||||
|
Net cash (used for) provided by financing activities
|
43,572 | (122,842 | ) | 163,548 | 68,458 | (241,975 | ) | (89,239 | ) | |||||||||||||||
|
Effect of exchange rate changes on cash and cash equivalents
|
— | — | — | (5,701 | ) | — | (5,701 | ) | ||||||||||||||||
|
Net (decrease) increase in cash and cash equivalents
|
(2,368 | ) | (2,657 | ) | 1,255 | (85,449 | ) | — | (89,219 | ) | ||||||||||||||
|
Cash and cash equivalents, beginning of period
|
10,659 | 2,753 | 4 | 517,890 | — | 531,306 | ||||||||||||||||||
|
Cash and cash equivalents, end of period
|
$ | 8,291 | $ | 96 | $ | 1,259 | $ | 432,441 | $ | — | $ | 442,087 | ||||||||||||
134
Table of Contents
Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 24 | Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited) |
The operations of our Oil and Gas operating segment focus on the
exploration for and the acquisition, development and production
of natural gas, oil and natural gas liquids in the United
States, the Canadian provinces of Alberta and British Columbia,
and Colombia.
Our Oil and Gas operating segment includes our wholly owned oil
and gas assets and our unconsolidated oil and gas joint
ventures. In December 2008, the SEC revised oil and gas
reporting disclosures, which clarified that we should consider
our equity-method investments when determining whether we have
significant oil and gas activities beginning in 2009. A one-year
deferral of the disclosure requirements was allowed if an entity
became subject to the requirements because of the change to the
definition of significant oil and gas activities. When operating
results from our wholly owned oil and gas activities were
considered with operating results from our unconsolidated oil
and gas joint ventures, which we account for under the equity
method of accounting, we determined that we had significant oil
and gas activities under the new definition. Accordingly, we are
presenting the information with regard to our oil and gas
producing activities as of and for the year ended
December 31, 2010.
The estimates of net proved natural gas and oil reserves are
based on reserve reports as of December 31, 2010, which
were prepared by independent petroleum engineers. AJM Petroleum
Consultants prepared reports of estimated proved oil and gas
reserves for our wholly owned assets in Canada. Miller and
Lents, Ltd. prepared reports of estimated proved oil and gas
reserves for both our wholly and our U.S. joint venture’s
interests in natural gas and oil properties located in the
United States. Netherland, Sewell & Associates, Inc.
prepared reports of estimated proved oil reserves for certain
oil properties located in Cat Canyon and West Cat Canyon Fields,
Santa Barbara County, California. Lonquist & Co., LLC
prepared reports of estimated proved oil and gas reserves for
our wholly owned assets in Colombia.
The following supplementary information includes our results of
operations for oil and gas production activities; capitalized
costs related to oil and gas producing activities; and costs
incurred in oil and gas property acquisition, exploration and
development. Supplemental information is also provided for the
estimated quantities of proved oil and gas reserves; the
standardized measure of discounted future net cash flows
associated with proved oil and gas reserves; and a summary of
the changes in the standardized measure of discounted future net
cash flows associated with proved oil and gas reserves.
Results
of Operations
Results of operations consist of all activities within our Oil
and Gas operating segment. Net revenues from production include
only the revenues from the production and sale of natural gas,
oil, and natural gas liquids. Production costs are those
incurred to operate and maintain wells and related equipment and
facilities used in oil and gas operations. Exploration expenses
include dry-hole costs, geological and geophysical expenses, and
the costs of retaining undeveloped leaseholds. Income tax
expense is calculated by applying the current statutory tax
rates to the revenues after deducting costs, which include
DD&A allowances, after giving
135
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
effect to permanent differences. The results of operations
exclude general office overhead and interest expense
attributable to oil and gas activities.
| For the Year Ended December 31, 2010 | ||||||||||||||||
|
United
|
||||||||||||||||
| States | Canada | Colombia | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Results of Operations
|
||||||||||||||||
|
Consolidated Subsidiaries
|
||||||||||||||||
|
Revenue
|
$ | 19,180 | $ | 11,276 | $ | 16,619 | $ | 47,075 | ||||||||
|
Production costs
|
8,510 | 7,965 | 7,918 | 24,393 | ||||||||||||
|
Exploration expenses
|
— | — | 39,047 | 39,047 | ||||||||||||
|
Depreciation and depletion
|
20,092 | 5,424 | 3,737 | 29,253 | ||||||||||||
|
Impairment of oil and gas properties
|
110,165 | — | — | 110,165 | ||||||||||||
|
Related income tax expense (benefit)
|
(15,856 | ) | (3,078 | ) | 610 | (18,324 | ) | |||||||||
|
Results of producing activities for consolidated subsidiaries
|
$ | (103,731 | ) | $ | 965 | $ | (34,693 | ) | $ | (137,459 | ) | |||||
|
Equity Companies(1)
|
||||||||||||||||
|
Revenue
|
$ | 64,736 | $ | 6,038 | $ | 20,176 | $ | 90,950 | ||||||||
|
Production costs
|
18,460 | 9,036 | 9,174 | 36,670 | ||||||||||||
|
Depreciation and depletion
|
24,221 | 6,033 | 7,058 | 37,312 | ||||||||||||
|
Impairment of oil and gas properties
|
851 | — | — | 851 | ||||||||||||
|
Realized gain on derivative instruments
|
(25,424 | ) | (2,543 | ) | — | (27,967 | ) | |||||||||
|
Related income tax expense (benefit)(2)
|
— | — | — | — | ||||||||||||
|
Results of producing activities for equity companies
|
$ | 46,628 | $ | (6,488 | ) | $ | 3,944 | $ | 44,084 | |||||||
|
Total results of operations
|
$ | (57,103 | ) | $ | (5,523 | ) | $ | (30,749 | ) | $ | (93,375 | ) | ||||
| (1) | Represents our proportionate share of interests in our equity companies. | |
| (2) | Equity companies are pass-through entities for tax purposes. |
Capitalized
Cost
Capitalized costs include the cost of properties, equipment and
facilities for oil and gas-producing activities. Capitalized
costs for proved properties include costs for oil and gas
leaseholds where proved reserves have been identified,
development wells, and related equipment and facilities,
including development wells in progress. Capitalized costs for
unproved properties include costs for acquiring oil and gas
leaseholds
136
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
where no proved reserves have been identified, including costs
of exploratory wells that are in the process of drilling or in
active completion, and costs of exploratory wells suspended or
waiting on completion.
| For the Year Ended December 31, 2010 | ||||||||||||||||
| United States | Canada | Colombia | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Capitalized Costs
|
||||||||||||||||
|
Consolidated Subsidiaries
|
||||||||||||||||
|
Property acquisition costs, proved
|
$ | 480,618 | $ | 62,109 | $ | 57,251 | $ | 599,978 | ||||||||
|
Property acquisition costs, unproved
|
136,625 | 89,785 | 1,174 | 227,584 | ||||||||||||
|
Total acquisition costs
|
617,243 | 151,894 | 58,425 | 827,562 | ||||||||||||
|
Accumulated depreciation and depletion
|
(463,330 | ) | (7,344 | ) | (3,782 | ) | (474,456 | ) | ||||||||
|
Net capitalized costs for consolidated subsidiaries
|
$ | 153,913 | $ | 144,550 | $ | 54,643 | $ | 353,106 | ||||||||
|
Equity Companies(1)
|
||||||||||||||||
|
Property acquisition costs, proved
|
$ | 749,515 | $ | 78,224 | $ | 98,629 | $ | 926,368 | ||||||||
|
Property acquisition costs, unproved
|
108,541 | 28,884 | 883 | 138,308 | ||||||||||||
|
Total acquisition costs
|
858,056 | 107,108 | 99,512 | 1,064,676 | ||||||||||||
|
Accumulated depreciation and depletion
|
(460,622 | ) | (72,338 | ) | (31,825 | ) | (564,785 | ) | ||||||||
|
Net capitalized costs for equity companies
|
$ | 397,434 | $ | 34,770 | $ | 67,687 | $ | 499,891 | ||||||||
| (1) | Represents our proportionate share of interests in our equity companies. |
Costs
Incurred in Oil and Gas Property Acquisitions, Exploration and
Development
Amounts reported as costs incurred include both capitalized
costs and costs charged to expense during 2010 for oil and gas
property acquisition, exploration and development activities.
Costs incurred also include new asset retirement obligations
established in the current year, as well as increases or
decreases to the asset retirement obligations resulting from
changes to cost estimates during the year. Exploration costs
include the costs of drilling and equipping successful
exploration wells, as well as dry-hole costs, geological and
137
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
geophysical expenses, and the costs of retaining undeveloped
leaseholds. Development costs include the costs of drilling and
equipping development wells, and construction of related
production facilities.
| For the Year Ended December 31, 2010 | ||||||||||||||||
|
United
|
||||||||||||||||
| States | Canada | Colombia | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Costs incurred in property acquisitions, exploration and
development activities
|
||||||||||||||||
|
Consolidated Subsidiaries
|
||||||||||||||||
|
Property acquisition costs, proved
|
$ | 25,080 | $ | — | $ | — | $ | 25,080 | ||||||||
|
Property acquisition costs, unproved
|
25,202 | — | 1,000 | 26,202 | ||||||||||||
|
Exploration costs
|
8,199 | — | 33,599 | 41,798 | ||||||||||||
|
Development costs
|
19,118 | 3,876 | — | 22,994 | ||||||||||||
|
Asset retirement costs
|
— | — | 770 | 770 | ||||||||||||
|
Total costs incurred for consolidated subsidiaries
|
$ | 77,599 | $ | 3,876 | $ | 35,369 | $ | 116,844 | ||||||||
|
Equity Companies(1)
|
||||||||||||||||
|
Property acquisition costs, proved
|
$ | 29,975 | $ | — | $ | — | $ | 29,975 | ||||||||
|
Property acquisition costs, unproved
|
34,207 | — | — | 34,207 | ||||||||||||
|
Exploration costs
|
108 | — | 29,927 | 30,035 | ||||||||||||
|
Development costs
|
118,828 | 1,056 | 11,805 | 131,689 | ||||||||||||
|
Asset retirement costs
|
296 | — | (104 | ) | 192 | |||||||||||
|
Total costs incurred for equity companies
|
$ | 183,414 | $ | 1,056 | $ | 41,628 | $ | 226,098 | ||||||||
| (1) | Represents our proportionate share of interests in equity companies. |
Oil and
Gas Reserves
The reserve disclosures that follow reflect estimates of proved
reserves for our consolidated subsidiaries and equity companies
of natural gas, oil, and natural gas liquids owned at
December 31, 2010 and changes in proved reserves during
2010. Our year-end reserve volumes for 2010 shown in the
following tables were calculated using average prices during the
12-month
period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period. These reserve
quantities are also used in calculating
unit-of-production
depreciation rates and in calculating the standardized measure
of discounted net cash flow. Estimates of volumes of proved
reserves of natural gas at year end are expressed in billions of
cubic feet (Bcf) at a pressure base of 14.73 pounds per square
inch for natural gas and in millions of barrels (MMBbls) for oil
and natural gas liquids.
For our wholly owned properties in the United States, the prices
used in our reserve reports were $3.72 per mcf for the
12-month
average of natural gas, $36.43 per barrel for liquid natural gas
and $61.12 per barrel for oil at December 31, 2010. The
prices used in our reserve reports by our unconsolidated
U.S. joint venture were $4.53 per mcf for the
12-month
average of natural gas, $39.04 per barrel for liquid natural gas
and $70.60 per barrel for oil at December 31, 2010. For our
wholly owned properties in Canada, the price used in our reserve
reports was $2.81 per mcf for the
12-month
average of natural gas at December 31, 2010. The
12-month
average price for natural gas used in the reserve report by our
unconsolidated Canada joint venture was $2.78 per mcf at
December 31, 2010. For our wholly owned properties in
Colombia, the price used in our reserve reports was $78.21 per
barrel for oil at December 31, 2010. The oil price used in
the reserve report by our unconsolidated Colombia joint venture
was $76.00 per barrel at December 31, 2010.
138
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible — from a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods and government regulations — prior to the time
at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain.
Revisions can include upward or downward changes in previously
estimated volumes of proved reserves for existing fields due to
the evaluation or re-evaluation of (1) already available
geologic, reservoir or production data, (2) new geologic,
reservoir or production data or (3) changes in average
prices and year-end costs that are used in the estimation of
reserves. This category can also include significant changes in
either development strategy or production equipment/facility
capacity.
Proved reserves include 100 percent of each majority-owned
affiliate’s participation in proved reserves and our
ownership percentage of the proved reserves of equity companies,
but exclude royalties and quantities due others.
In the proved reserves tables, consolidated reserves and equity
company reserves are reported separately. However, we do not
view equity company reserves any differently than those from our
consolidated subsidiaries.
Net proved developed reserves are those volumes that are
expected to be recovered through existing wells with existing
equipment and operating methods or in which the cost of the
required equipment is relatively minor compared to the cost of a
new well. Net proved undeveloped reserves are those volumes that
are
139
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion.
| United States | Canada | Colombia | Total | |||||||||||||||||||||||||||||
|
Natural
|
Natural
|
Natural
|
Natural
|
|||||||||||||||||||||||||||||
|
Liquids
|
Gas
|
Liquids
|
Gas
|
Liquids
|
Gas
|
Liquids
|
Gas
|
|||||||||||||||||||||||||
| Reserves | (MMBbls) | (Bcf) | (MMBbls) | (Bcf) | (MMBbls) | (Bcf) | (MMBbls) | (Bcf) | ||||||||||||||||||||||||
|
Net proved reserves of consolidated subsidiaries
|
||||||||||||||||||||||||||||||||
|
January 1, 2010
|
0.4 | 29.6 | — | 5.0 | 0.9 | — | 1.3 | 34.6 | ||||||||||||||||||||||||
|
Revisions
|
0.1 | (11.7 | ) | — | 3.6 | (0.7 | ) | — | (0.6 | ) | (8.1 | ) | ||||||||||||||||||||
|
Extensions, additions and discoveries
|
— | 5.0 | — | — | 2.0 | — | 2.0 | 5.0 | ||||||||||||||||||||||||
|
Production
|
(0.1 | ) | (3.1 | ) | — | (3.1 | ) | (0.2 | ) | — | (0.3 | ) | (6.2 | ) | ||||||||||||||||||
|
Purchases in place
|
20.8 | — | — | — | — | — | 20.8 | — | ||||||||||||||||||||||||
|
Sales in place
|
— | — | — | — | — | — | — | — | ||||||||||||||||||||||||
|
December 31, 2010
|
21.2 | 19.8 | — | 5.5 | 2.0 | — | 23.2 | 25.3 | ||||||||||||||||||||||||
|
Proportional interest in proved reserves of equity
companies
|
||||||||||||||||||||||||||||||||
|
January 1, 2010
|
5.2 | 466.9 | — | 7.5 | 0.6 | — | 5.8 | 474.4 | ||||||||||||||||||||||||
|
Revisions
|
1.5 | (119.1 | ) | — | (0.8 | ) | 0.5 | — | 2.0 | (119.9 | ) | |||||||||||||||||||||
|
Extensions, additions and discoveries
|
0.6 | 108.5 | — | — | 1.3 | — | 1.9 | 108.5 | ||||||||||||||||||||||||
|
Production
|
(0.2 | ) | (12.3 | ) | — | (1.5 | ) | (0.3 | ) | — | (0.5 | ) | (13.8 | ) | ||||||||||||||||||
|
Purchases in place
|
0.8 | 109.8 | — | — | — | — | 0.8 | 109.8 | ||||||||||||||||||||||||
|
Sales in place
|
— | (1.0 | ) | — | — | (0.2 | ) | — | (0.2 | ) | (1.0 | ) | ||||||||||||||||||||
|
December 31, 2010
|
7.9 | 552.8 | — | 5.2 | 1.9 | — | 9.8 | 558.0 | ||||||||||||||||||||||||
|
Total proved reserves at December 31, 2010
|
29.1 | 572.6 | — | 10.7 | 3.9 | — | 33.0 | 583.3 | ||||||||||||||||||||||||
|
Proved Developed Reserves at December 31, 2010
|
||||||||||||||||||||||||||||||||
|
Consolidated subsidiaries
|
2.7 | 17.1 | — | 5.5 | 1.6 | — | 4.3 | 22.6 | ||||||||||||||||||||||||
|
Equity companies
(1)
|
3.0 | 147.1 | — | 5.2 | 0.5 | — | 3.5 | 152.3 | ||||||||||||||||||||||||
|
Proved Undeveloped Reserves at December 31, 2010
|
||||||||||||||||||||||||||||||||
|
Consolidated subsidiaries
|
18.5 | 2.7 | — | — | 0.4 | — | 18.9 | 2.7 | ||||||||||||||||||||||||
|
Equity companies
(1)
|
4.9 | 405.7 | — | — | 1.4 | — | 6.3 | 405.7 | ||||||||||||||||||||||||
| (1) | Represents our proportionate share of interests in equity companies. |
Standardized
Measure of Discounted Future Cash Flows
For the year ended December 31, 2010, the standardized
measure of discounted future net cash flow was computed by
applying
first-day-of-the-month
average prices, year-end costs and legislated tax rates and a
discount factor of 10 percent to proved reserves. Estimated
future net cash flows for all periods presented are reduced by
estimated future development, production, abandonment and
dismantlement costs based on existing costs, assuming
continuation of existing economic conditions, and by estimated
future income tax expense. These estimates also include
assumptions about the timing of future production of proved
reserves, and timing
140
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
of future development, production costs, and abandonment and
dismantlement. Income tax expense, both U.S. and global, is
calculated by applying the existing statutory tax rates,
including any known future changes, to the pretax net cash flows
giving effect to any permanent differences and reduced by the
applicable tax basis. The 10-percent discount factor is
prescribed by GAAP.
The present value of future net cash flows does not purport to
be an estimate of the fair market value of our consolidated
subsidiaries and equity companies’ proved reserves. An
estimate of fair value would also take into account, among other
things, anticipated changes in future prices and costs, the
expected recovery of reserves in excess of proved reserves and a
discount factor more representative of the time value of money
and the risks inherent in producing oil and gas. Significant
changes in estimated reserve volumes or commodity prices could
have a material effect on our consolidated financial statements.
| For the Year Ended December 31, 2010 | ||||||||||||||||
| United States | Canada | Colombia | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Standardized Measure of Discounted Future Cash Flows
|
||||||||||||||||
|
Consolidated Subsidiaries
|
||||||||||||||||
|
Future cash flows from sales of oil and gas
|
$ | 1,468,944 | $ | 16,435 | $ | 156,921 | $ | 1,642,300 | ||||||||
|
Future production costs
|
(481,487 | ) | (5,600 | ) | (83,556 | ) | (570,643 | ) | ||||||||
|
Future development costs
|
(152,309 | ) | (360 | ) | (16,216 | ) | (168,885 | ) | ||||||||
|
Future income tax expense(2)
|
(268,774 | ) | — | — | (268,774 | ) | ||||||||||
|
Future net cash inflows
|
566,374 | 10,475 | 57,149 | 633,998 | ||||||||||||
|
Effect of discounting net cash flows at 10%
|
(353,232 | ) | (2,046 | ) | (10,256 | ) | (365,534 | ) | ||||||||
|
Discounted future net cash flows
|
$ | 213,142 | $ | 8,429 | $ | 46,893 | $ | 268,464 | ||||||||
|
Equity Companies(1)
|
||||||||||||||||
|
Future cash flows from sales of oil and gas
|
$ | 2,889,308 | $ | 14,713 | $ | 141,410 | $ | 3,045,431 | ||||||||
|
Future production costs
|
(752,792 | ) | (6,463 | ) | (56,837 | ) | (816,092 | ) | ||||||||
|
Future development costs
|
(850,053 | ) | (992 | ) | (12,307 | ) | (863,352 | ) | ||||||||
|
Future income tax expense(3)
|
— | — | — | — | ||||||||||||
|
Future net cash inflows
|
1,286,463 | 7,258 | 72,266 | 1,365,987 | ||||||||||||
|
Effect of discounting net cash flows at 10%
|
(995,091 | ) | (1,477 | ) | (14,313 | ) | (1,010,881 | ) | ||||||||
|
Discounted future net cash flows
|
$ | 291,372 | $ | 5,781 | $ | 57,953 | $ | 355,106 | ||||||||
|
Total consolidated and equity interests in standardized
measure of discounted future net cash flows
|
$ | 504,514 | $ | 14,210 | $ | 104,846 | $ | 623,570 | ||||||||
| (1) | Represents our proportionate share of interests in equity companies. | |
| (2) | For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings. | |
| (3) | Equity companies are pass-through entities for tax purposes. |
141
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Nabors
Industries Ltd. and Subsidiaries
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Change
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
The following table reflects the estimate of changes in the
standardized measure of discounted future net cash flows from
proved reserves:
| For the Year Ended December 31, 2010 | ||||||||||||||||
|
United
|
||||||||||||||||
| States | Canada | Colombia | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Change in Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil and Gas Reserves
|
||||||||||||||||
|
Consolidated Subsidiaries
|
||||||||||||||||
|
Discounted future net cash flows as of December 31, 2009
|
$ | 38,345 | $ | 6,527 | $ | 11,741 | $ | 56,613 | ||||||||
|
Value of reserves added during the year due to extensions,
discoveries and net purchase less related costs
|
8,037 | — | 45,072 | 53,109 | ||||||||||||
|
Changes in value of previous-year reserves due to:
|
||||||||||||||||
|
Sales of oil and gas produced, net of production costs
|
(10,670 | ) | (3,311 | ) | (8,701 | ) | (22,682 | ) | ||||||||
|
Development costs incurred during the year
|
8,359 | — | — | 8,359 | ||||||||||||
|
Net change in prices and production costs
|
96,662 | 46 | (2,555 | ) | 94,153 | |||||||||||
|
Net change in future development costs
|
4,155 | (192 | ) | 285 | 4,248 | |||||||||||
|
Revisions of previous reserves estimates
|
(27,501 | ) | 5,628 | (7,093 | ) | (28,966 | ) | |||||||||
|
Purchases of reserves
|
196,613 | — | — | 196,613 | ||||||||||||
|
Accretion of discount
|
3,562 | 496 | 1,030 | 5,088 | ||||||||||||
|
Other
|
(17,357 | ) | (765 | ) | 7,114 | (11,008 | ) | |||||||||
|
Net change in income taxes(2)
|
(87,063 | ) | — | — | (87,063 | ) | ||||||||||
|
Total change in the standardized measure for consolidated
subsidiaries
|
$ | 174,797 | $ | 1,902 | $ | 35,152 | $ | 211,851 | ||||||||
|
Discounted future net cash flows as of December 31, 2010
|
$ | 213,142 | $ | 8,429 | $ | 46,893 | $ | 268,464 | ||||||||
|
Equity Companies(1)
|
||||||||||||||||
|
Discounted future net cash flows as of December 31, 2009
|
$ | 52,941 | $ | 9,569 | $ | 13,706 | $ | 76,216 | ||||||||
|
Value of reserves added during the year due to extensions,
discoveries and net purchase less related costs
|
20,230 | — | 40,664 | 60,894 | ||||||||||||
|
Changes in value of previous-year reserves due to:
|
||||||||||||||||
|
Sales of oil and gas produced, net of production costs
|
(46,276 | ) | 2,998 | (11,002 | ) | (54,280 | ) | |||||||||
|
Development costs incurred during the year
|
69,207 | — | — | 69,207 | ||||||||||||
|
Net change in prices and production costs
|
90,974 | (5,205 | ) | 3,032 | 88,801 | |||||||||||
|
Net change in future development costs
|
— | (374 | ) | (847 | ) | (1,221 | ) | |||||||||
|
Revisions of previous reserves estimates
|
76,723 | (1,077 | ) | 17,289 | 92,935 | |||||||||||
|
Purchases of reserves
|
5,453 | — | — | 5,453 | ||||||||||||
|
Sales of reserves
|
(1,446 | ) | — | (5,418 | ) | (6,864 | ) | |||||||||
|
Accretion of discount
|
5,294 | 794 | 529 | 6,617 | ||||||||||||
|
Other
|
18,272 | (924 | ) | — | 17,348 | |||||||||||
|
Net change in income taxes(3)
|
— | — | — | — | ||||||||||||
|
Total change in the standardized measure for equity companies
|
$ | 238,431 | $ | (3,788 | ) | $ | 44,247 | $ | 278,890 | |||||||
|
Discounted future net cash flows as of December 31, 2010
|
$ | 291,372 | $ | 5,781 | $ | 57,953 | $ | 355,106 | ||||||||
| (1) | Represents our proportionate share of interests in equity companies. | |
| (2) | For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings. | |
| (3) | Equity companies are pass-through entities for tax purposes. |
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Table of Contents
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
Not applicable.
| ITEM 9A. | CONTROLS AND PROCEDURES |
(a) Disclosure Controls and Procedures. We maintain a set
of disclosure controls and procedures designed to provide
reasonable assurance that information required to be disclosed
in our reports filed under the Exchange Act is recorded,
processed, summarized and reported within the time periods
specified in the SEC’s rules and forms. We have investments
in certain unconsolidated entities that we do not control or
manage. Because we do not control or manage these entities, our
disclosure controls and procedures with respect to these
entities are necessarily more limited than those we maintain
with respect to our consolidated subsidiaries.
The Company’s management, with the participation of the
Company’s Chairman and Chief Executive Officer and
principal accounting and financial officer, has evaluated the
effectiveness of the Company’s disclosure controls and
procedures (as such term is defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) as of the end of the period covered by
this report. Based on this evaluation, the Company’s
Chairman and Chief Executive Officer and principal accounting
and financial officer have concluded that, as of the end of the
period, the Company’s disclosure controls and procedures
are effective, at the reasonable assurance level, in recording,
processing, summarizing and reporting, on a timely basis,
information required to be disclosed by the Company in reports
that it files or submits under the Exchange Act and are
effective, at the reasonable assurance level, in ensuring that
information required to be disclosed by the Company in the
reports that it files or submits under the Exchange Act is
accumulated and communicated to the Company’s management,
including the Company’s Chairman and Chief Executive
Officer and principal accounting and financial officer, as
appropriate to allow timely decisions regarding required
disclosure.
(b) Changes in Internal Control Over Financial Reporting.
There have not been any changes in the Company’s internal
control over financial reporting (identified in connection with
the evaluation required by paragraph (d) in
Rules 13a-15
and
15d-15
under the Exchange Act) during the most recently completed
fiscal quarter that have materially affected, or are reasonably
likely to materially affect, the Company’s internal control
over financial reporting.
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Management’s
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining
adequate internal control over financial reporting. Our internal
control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements
for external purposes in accordance with GAAP. Our internal
control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the Company;
(ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial
statements in accordance with GAAP, and that receipts and
expenditures of the Company are being made only in accordance
with authorizations of management and directors of the Company;
and (iii) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or
disposition of the Company’s assets that could have a
material effect on the financial statements.
Internal control over financial reporting cannot provide
absolute assurance of achieving financial reporting objectives
because of its inherent limitations. Internal control over
financial reporting is a process that involves human diligence
and compliance and is subject to lapses in judgment and
breakdowns resulting from human failures. Internal control over
financial reporting also can be circumvented by collusion or
improper management override. Because of these limitations,
there is a risk that material misstatements may not be prevented
or detected on a timely basis by internal control over financial
reporting. However, these inherent limitations are known
features of the financial reporting process. Therefore, it is
possible to design into the process safeguards to reduce, though
not eliminate, this risk.
Management conducted an evaluation of the effectiveness of the
Company’s internal control over financial reporting based
on the framework in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). Based on this evaluation,
management concluded that the Company’s internal control
over financial reporting was effective as of December 31,
2010. Management excluded the acquisition of Superior Well
Services, Inc. (“Superior”) from the assessment of
internal control over financial reporting as of
December 31, 2010 because Superior was acquired in a
business combination on September 10, 2010. Superior’s
total assets and revenues constitute 10 and 8 percent,
respectively, of our related consolidated financial statements
as of and for the year ended December 31, 2010.
PricewaterhouseCoopers LLP has issued a report on the
effectiveness of internal control over financial reporting,
which is included in Part II, Item 8 of this report.
| ITEM 9B. | OTHER INFORMATION |
Not applicable.
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| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The information called for by this item will be contained in the
definitive Proxy Statement to be distributed in connection with
our 2011 annual meeting of shareholders under the captions
“
Election of Directors
”, “
Other
Executive Officers
”, “
Section 16(a)
Beneficial Ownership Reporting Compliance
”, and is
incorporated into this document by reference.
We have adopted a Code of Business Conduct that satisfies the
SEC’s definition of a “Code of Ethics” and
applies to all employees, including our principal executive
officer, principal financial officer, and principal accounting
officer. The Code of Ethics is posted on our website at
www.nabors.com
. We intend to disclose on our website any
amendments to the Code of Conduct and any waivers of the Code of
Conduct that apply to our principal executive officer, principal
financial officer, and principal accounting officer.
On June 30, 2010, we filed with the New York Stock
Exchange, or NYSE, the Annual CEO Certification regarding our
compliance with the NYSE’s Corporate Governance listing
standards as required by
Section 303A-12(a)
of the NYSE Listed Company Manual.
| ITEM 11. | EXECUTIVE COMPENSATION |
The information called for by this item will be contained in our
definitive Proxy Statement to be distributed in connection with
our 2011 annual meeting of shareholders under the caption
“
Management Compensation
” and except as
specified in the following sentence, is incorporated into this
document by reference. Information in Nabors’ 2011 proxy
statement not deemed to be “soliciting material” or
“filed” with the Commission under its rules, including
the Compensation Committee Report, is not deemed to be
incorporated by reference.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS |
We maintain five different equity compensation plans: 1996
Employee Stock Plan, 1997 Executive Officers Incentive Stock
Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for
Non-Employee Directors and 2003 Employee Stock Plan pursuant to
which we may grant equity awards to eligible persons. The terms
of our equity compensation plans are described more fully below.
The following table gives information about these equity
compensation plans as of December 31, 2010:
|
(a)
|
(c)
|
|||||||||||
|
Number of
|
Number of Securities
|
|||||||||||
|
Securities to be
|
(b)
|
Remaining Available for
|
||||||||||
|
Issued Upon
|
Weighted-Average
|
Future Issuance Under
|
||||||||||
|
Exercise of
|
Exercise Price of
|
Equity Compensation
|
||||||||||
|
Outstanding
|
Outstanding
|
Plans (Excluding
|
||||||||||
|
Options, Warrants
|
Options, Warrants
|
Securities
|
||||||||||
| Plan category | and Rights | and Rights | Reflected in Column (a)) | |||||||||
|
Equity compensation plans approved by security holders
|
24,618,032 | $ | 17.9089 | 17,282,075 | ||||||||
|
Equity compensation plans not approved by security holders
|
4,313,779 | $ | 23.4348 | 847,357 | ||||||||
|
Total
|
28,931,811 | 18,129,432 | ||||||||||
| (1) | The 1996 Employee Stock Plan incorporated an evergreen formula pursuant to which on each January 1, the aggregate number of shares reserved for issuance under the plan were increased by an amount equal to 1 1/2 % of the common shares outstanding on September 30 of the immediately preceding fiscal year. The 1996 Employee Stock Plan expired on January 17, 2006. | |
| (2) | The 2003 Employee Stock Plan provides, commencing on June 1, 2006 and thereafter for a period of four (4) years on each January 1, for an automatic increase in the number of shares reserved and available for |
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| issuance under the Plan by an amount equal to two percent (2%) of the Company’s outstanding common shares as of each June 1 or January 1 date. |
Following is a brief summary of the material terms of the plans
that have not been approved by our shareholders. Unless
otherwise indicated, (1) each plan is administered by an
independent committee appointed by the Company’s Board of
Directors; (2) the exercise price of options granted under
each plan must be no less than 100% of the fair market value per
common share on the date of the grant of the option;
(3) the term of an award granted under each plan may not
exceed 10 years; (4) options granted under the plan
are nonstatutory options (“NSOs”) not intended to
qualify under Section 422 of the Internal Revenue Code of
1986, as amended (the “IRC”); and (5) unless
otherwise determined by the committee in its discretion, options
may not be exercised after the optionee has ceased to be
employed by the Company.
1998
Employee Stock Plan
The plan reserves for issuance up to 35,000,000 common shares of
the Company pursuant to the exercise of options granted under
the plan. The persons eligible to participate in the plan are
employees and consultants of the Company. Options granted to
employees may either be awards of shares, non-qualified stock
options (each, an “NQSO”), incentive stock options
(each, an “ISO”) or stock appreciation rights (each,
an “SAR”). An optionee may reduce the option exercise
price by paying the Company in cash, shares, options, or the
equivalent, an amount equal to the difference between the
exercise price and the reduced exercise price of the option. The
administrative committee must establish performance goals for
stock awards in writing not later than the date required for
compliance under Section 162(m) of the IRC, and vesting of
these shares is contingent upon the attainment of such
performance goals. Stock awards vest over a period determined by
the Committee, which period must expire no later than
January 9, 2008. The committee may grant ISOs of not less
than 100% of the fair market value per common share on the date
of grant; except that in the event the optionee owns on the date
of grant, securities possessing more than 10% of the total
combined voting power of all classes of securities of the
Company or of any subsidiary of the Company, the price per share
must not be less than 110% of the fair market value per common
share on the date of the grant. The option must expire five
years from the date it is granted. SARs may be granted in
conjunction with all or part of any option granted under the
plan, in which case the exercise of the SAR must require the
cancellation of a corresponding portion of the option;
conversely, the exercise of the option will result in
cancellation of a corresponding portion of the SAR. In the case
of a NQSO, SARs may be granted either at or after the time of
grant of the option. In the case of an ISO, SARs may be granted
only at the time of grant of the option. A SAR may also be
granted on a stand-alone basis. The term of a SAR must be
established by the committee. The exercise price of a SAR cannot
be less than 100% of the fair market value per common share on
the date of grant. The committee has the authority to make
provisions in its award and grant agreements to address vesting
and other issues arising in connection with a change of control.
1999
Stock Option Plan for Non-Employee Directors
The plan reserves for issuance up to 3,000,000 common shares of
the Company pursuant to the exercise of options granted under
the plan. The plan is administered by the Company’s Board
of Directors or a committee appointed by the Board to administer
the plan. Eligible directors may not consider or vote on the
administration of the plan or serve as a member of the
committee. Options may be granted under the plan to non-employee
directors of the Company. Options vest and become
non-forfeitable on the first anniversary of the option grant if
the optionee has continued to serve as a director until that
day, unless otherwise provided. In the event of termination of
an optionee’s service as a director by reason of voluntary
retirement, declining to stand for re-election or becoming a
full-time employee of the Company or a subsidiary of the
Company, all unvested options granted under the Plan
automatically expire and are not exercisable, and all
unexercised options continue to be exercisable until their
stated expiration date. In the event of death or disability of
an optionee while the optionee is a director, the
then-outstanding options of such optionee become exercisable for
two years from the date of the death or disability. All unvested
options automatically vest and become non-forfeitable as of the
date of death or disability and become exercisable for two years
from the date of the death of the optionee or until the stated
expiration date, whichever is earlier. In the event of the
termination of
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an optionee’s service as a director by the Board of
Directors for cause or the failure of such director to be
re-elected, the administrator of the plan in its sole discretion
can cancel the then-outstanding options of such optionee,
including options that have vested and such options
automatically expire and become non-exercisable on the effective
date of such termination.
The remainder of the information called for by this item will be
contained in our definitive Proxy Statement to be distributed in
connection with our 2011 annual meeting of shareholders under
the caption “
Share Ownership of Management and Principal
Shareholders
” and is incorporated into this document by
reference.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
The information called for by this item will be contained in our
definitive Proxy Statement to be distributed in connection with
our 2011 annual meeting of shareholders under the caption
“
Certain Relationships and Related
Transactions
” and is incorporated into this document by
reference.
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
The information called for by this item will be contained in our
definitive Proxy Statement to be distributed in connection with
our 2011 annual meeting of shareholders under the caption
“Principal Accounting Fees and Services”
and is
incorporated into this document by reference.
147
| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULE |
(a) The following documents are filed as part of this
report:
(1) Financial Statements
| Page No. | ||||
|
Consolidated Balance Sheets as of December 31, 2010 and 2009
|
65 | |||
|
Consolidated Statements of Income (Loss) for the Years Ended
December 31, 2010, 2009 and 2008
|
66 | |||
|
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2010, 2009 and 2008
|
67 | |||
|
Consolidated Statements of Changes in Equity for the Years Ended
December 31, 2010, 2009 and 2008
|
68 | |||
(2) Financial Statement Schedules
| Page No. | ||||
| 154 | ||||
All other supplemental schedules are omitted because of the
absence of the conditions under which they would be required or
because the required information is included in the financial
statements or related notes.
| (b) | Exhibits |
| Exhibit No. | Description | |||
| 2 | .1 | Agreement and Plan of Merger among Nabors Industries, Inc., Nabors Acquisition Corp. VIII, Nabors Industries Ltd. and Nabors US Holdings Inc. (incorporated by reference to Annex I to the proxy statement/prospectus included in our Registration Statement on Form S-4 (File No. 333-76198) filed with the SEC on May 10, 2002, as amended). | ||
| 2 | .2 | Asset Purchase Agreement dated July 20, 2007, by and among Nabors US Finance LLC, Nabors Well Services Co. (inclusive of its Sea Mar Division), Sea Mar Management LLC and Hornbeck Offshore Services, Inc. (incorporated by reference to Exhibit 2.5 to our Form 10-Q (File No. 001-32657) filed with the SEC on August 2, 2007). | ||
| 2 | .3 | Agreement and Plan of Merger, by and among Nabors Industries Ltd., Diamond Acquisition Corp., and Superior, dated as of August 6, 2010 (incorporated by reference to Exhibit 2.2 to our Form 8-K (File No. 001-32657) filed with the SEC on August 9, 2010). | ||
| 3 | .1 | Memorandum of Association of Nabors Industries Ltd. (incorporated by reference to Annex II to the proxy statement/prospectus included in our Registration Statement on Form S-4 (File No. 333-76198) filed with the SEC on May 10, 2002, as amended). | ||
| 3 | .2 | Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit 4.2 to our Form 10-Q (File No. 000-49887) filed with the SEC on August 3, 2005). | ||
| 3 | .2(a) | Amendment to Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit A of our Proxy Statement (File No. 001-32657) filed with the SEC on February 24, 2006). | ||
| 3 | .3 | Form of Resolutions of our Board of Directors authorizing the issue of the Special Voting Preferred Share (incorporated by reference to Exhibit 3.3 to our Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (File No. 333-85228-99) filed with the Commission on June 11, 2002). | ||
| 4 | .1 | Indenture, dated August 22, 2002, among Nabors Industries, Inc., as issuer, Nabors Industries Ltd., as guarantor, and Bank One, N.A., with respect to Nabors Industries, Inc.’s Series A and Series B 5.375% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to Nabors Industries, Inc.’s Registration Statement on Form S-4 (File No. 333-10049201) filed with the SEC on October 11, 2002). | ||
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| Exhibit No. | Description | |||
| 4 | .2 | Purchase Agreement, dated May 18, 2006, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and Lehman Brothers Inc., with respect to Nabors Industries, Inc.’s 0.94% Senior Exchangeable Notes due 2011 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on May 24, 2006). | ||
| 4 | .2(a) | Indenture, dated as of May 23, 2006, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 0.94% Senior Exchangeable Notes due 2011 (including form of 0.94% Senior Exchangeable Note due 2011) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on May 24, 2006). | ||
| 4 | .2(b) | Registration Rights Agreement, dated as of May 23, 2006, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and Lehman Brothers Inc., with respect to Nabors Industries, Inc.’s 0.94% Senior Exchangeable Notes due 2011 (incorporated by reference to Exhibit 4.3 to our Form 8-K (File No. 001-32657) filed with the SEC on May 24, 2006). | ||
| 4 | .3 | Purchase Agreement, dated February 14, 2008, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008). | ||
| 4 | .3(a) | Indenture, dated February 20, 2008, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (including form of 6.15% Senior Note due 2018) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008). | ||
| 4 | .3(b) | Registration Rights Agreement, dated as of February 20, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.3 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008). | ||
| 4 | .4 | Purchase Agreement, dated July 17, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on July 23, 2008). | ||
| 4 | .4(a) | Registration Rights Agreement, dated July 22, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on July 23, 2008). | ||
| 4 | .5 | Purchase Agreement, dated January 7, 2009, among Nabors Industries, Inc., Nabors Industries Ltd., Goldman, Sachs & Co., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Howard Weil Incorporated, J.P. Morgan Securities Inc., Morgan Stanley & Co. Incorporated, Tudor, Pickering, Holt & Co. Securities, Inc. and Wells Fargo Securities, LLC, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on January 14, 2009). | ||
| 4 | .5(a) | Indenture related to the Senior Notes due 2019, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (including form of 9.25% Senior Note due 2019) (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on January 14, 2009). | ||
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| Exhibit No. | Description | |||
| 4 | .5(b) | Registration Rights Agreement, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd., Goldman, Sachs & Co., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Howard Weil Incorporated, J.P. Morgan Securities Inc., Morgan Stanley & Co. Incorporated, Tudor, Pickering, Holt & Co. Securities, Inc. and Wells Fargo Securities, LLC, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on January 14, 2009). | ||
| 4 | .6 | Purchase Agreement, dated September 9, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Mizuho Securities USA Inc., Banc of America Securities LLC, Morgan Stanley & Co. Incorporated, HSBC Securities (USA) Inc., PNC Capital Markets LLC and Scotia Capital (USA) Inc. (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010). | ||
| 4 | .6(a) | Indenture related to the 5.0% Senior Notes due 2020, dated as of September 14, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., Wilmington Trust Company, as trustee and Citibank, N.A. as securities administrator (including form of 5.0% Senior Note due 2020) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010). | ||
| 4 | .6(b) | Registration Rights Agreement, dated as of September 14, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Mizuho Securities USA Inc., Banc of America Securities LLC, Morgan Stanley & Co. Incorporated, HSBC Securities (USA) Inc., PNC Capital Markets LLC and Scotia Capital (USA) Inc. (incorporated by reference to Exhibit 4.3 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010). | ||
| 4 | .7 | Tender and Voting Agreement, by and among Nabors Industries Ltd., Diamond Acquisition Corp, and certain Superior stockholders, dated as of August 6, 2010 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on August 9, 2010). | ||
| 10 | .1 (+) | Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of April 1, 2009 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on April 30, 2009). | ||
| 10 | .1(a) (+) | First Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of June 29, 2009 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2009). | ||
| 10 | .1(b) (+) | Second Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of December 28, 2009 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on December 28, 2009). | ||
| 10 | .2 (+) | Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of April 1, 2009 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on April 30, 2009). | ||
| 10 | .2(a) (+) | First Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of June 29, 2009 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2009). | ||
| 10 | .2(b) (+) | Second Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of December 28, 2009 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on December 28, 2009). | ||
| 10 | .2(c) (+) | Employment Agreement effective October 1, 1996, among Nabors Industries, Inc. and Anthony G. Petrello (incorporated by reference to Exhibit 10.8 to our Form 10-Q (File No. 1-9245) filed May 16, 1997). | ||
| 10 | .3 | Form of Indemnification Agreement entered into between Nabors Industries Ltd. and the directors and executive officers identified in the schedule thereto (incorporated by reference to Exhibit 10.28 to our Form 10-K (File No. 000-49887) filed with the SEC on March 31, 2003). | ||
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| Exhibit No. | Description | |||
| 10 | .4 (+) | Form of Stock Option Agreement — Isenberg/Petrello (incorporated by reference to Exhibit 10.03 to our Form 8-K (File No. 000-49887) filed with the SEC on March 2, 2005). | ||
| 10 | .5 (+) | Form of Stock Option Agreement — Others (incorporated by reference to Exhibit 10.04 to our Form 8-K (File No. 000-49887) filed with the SEC on March 2, 2005). | ||
| 10 | .6 (+) | 2003 Employee Stock Plan (incorporated by reference to Annex D of our Proxy Statement (File No. 000-49887) filed with the SEC on May 8, 2003). | ||
| 10 | .6(a) (+) | First Amendment to 2003 Employee Stock Plan (incorporated by reference to Exhibit 4.1 to our Form 10-Q (File No. 000-49887) filed with the SEC on August 3, 2005). | ||
| 10 | .6(b) (+) | Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of our Proxy Statement (File No. 001-32657) filed with the SEC on May 4, 2006). | ||
| 10 | .6(c) (+) | Nabors Industries Ltd. Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of Nabors Industries Ltd.’s Revised Definitive Proxy Statement on Schedule 14A (File No. 001-32657) filed with the Commission on May 4, 2006) (incorporated by reference to Exhibit 99.1 to our Form S-8 filed with the SEC on November 12, 2008. | ||
| 10 | .7(+) | 1996 Employee Stock Plan (incorporated by reference to Nabors Industries Inc.’s Registration Statement on Form S-8 (File No. 333-11313) filed with the SEC on September 3, 1996). | ||
| 10 | .8 (+) | Nabors Industries, Inc. 1997 Executive Officers Incentive Stock Plan (incorporated by reference to Exhibit 10.20 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed with the SEC on December 29, 1997). | ||
| 10 | .9 (+) | Nabors Industries, Inc. 1998 Employee Stock Plan (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed with the SEC on March 31, 1999). | ||
| 10 | .10 (+) | Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.21 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed with the SEC March 31, 1999). | ||
| 10 | .10(a) (+) | Amendment to Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.’s Form 10-K (File No. 1-09245) filed with the SEC on March 19, 2002). | ||
| 10 | .10(b) (+) | Amended and Restated 1999 Stock Option Plan for Non-Employee Directors (amended on May 2, 2003) (incorporated by reference to Exhibit 10.29 to our Form 10-Q (File No. 000-49887) filed with the SEC on May 12, 2003). | ||
| 10 | .11 | Purchase and Sale Agreement (Red River) by and among El Paso Production Company and El Paso Production GOM Inc., jointly and severally as Seller and Ramshorn Investments, Inc., as Purchaser dated October 8, 2003 (incorporated by reference to Exhibit 10.23 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004). | ||
| 10 | .12 | Purchase and Sale Agreement (USA) between El Paso Production Oil & Gas USA, L.P., as Seller and Ramshorn Investments, Inc., as Purchaser dated October 8, 2003 (incorporated by reference to Exhibit 10.24 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004). | ||
| 10 | .13 | Credit Agreement, dated as of September 7, 2010, among Nabors Industries, Inc., as borrower, Nabors Industries Ltd., as guarantor, UBS Securities LLC, Citibank, N.A., Deutsche Bank AG New York Branch and Mizuho Corporate Bank (USA), as joint lead arrangers and joint bookrunners, UBS Securities LLC, as documentation agent and syndication agent, UBS AG, Stamford Branch, as administrative agent, the lenders party thereto from time to time and UBS Loan Finance, LLC, as swingline lender (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on September 7, 2010). | ||
| 12 | Computation of Ratios. * | |||
| 14 | Code of Business Conduct (incorporated by reference to Exhibit 14 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004). | |||
151
Table of Contents
| Exhibit No. | Description | |||
| 18 | Preference Letter of Independent Accountants Regarding Change in Accounting Principle (incorporated by reference to Exhibit 18 to our Form 10-Q (File No. 000-49887) filed with the SEC on November 2, 2005). | |||
| 21 | Significant Subsidiaries* | |||
| 23 | .1 | Consent of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP — Houston. * | ||
| 23 | .2 | Consent of Independent Auditors — Ernst & Young LLC — Houston. * | ||
| 23 | .3 | Consent of Miller and Lents, Ltd.* | ||
| 23 | .4 | Consent of Netherland, Sewell & Associates, Inc.* | ||
| 23 | .5 | Consent of AJM Petroleum Consultants* | ||
| 23 | .6 | Consent of Lonquist & Co., LLC* | ||
| 23 | .7 | Consent of Miller and Lents, Ltd.- NFR Energy LLC* | ||
| 31 | .1 | Rule 13a-14(a)/15d-14(a) Certification of Eugene M. Isenberg, Chairman and Chief Executive Officer* | ||
| 31 | .2 | Rule 13a-14(a)/15d-14(a) Certification of R. Clark Wood, principal accounting and financial officer* | ||
| 32 | .1 | Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Eugene M. Isenberg, Chairman and Chief Executive Officer and R. Clark Wood, principal accounting and financial officer (furnished herewith). | ||
| 99 | .1 | Report of Miller and Lents, Ltd.* | ||
| 99 | .2 | Report of Netherland, Sewell & Associates, Inc.* | ||
| 99 | .3 | Report of AJM Petroleum Consultants* | ||
| 99 | .4 | Report of Lonquist & Co., LLC* | ||
| 99 | .5 | Report of Miller and Lents, Ltd. — NFR Energy LLC* | ||
| 99 | .6 | Financial Statements and Notes for NFR Energy LLC* | ||
| * | Filed herewith. |
| (+) | Management contract or compensatory plan or arrangement. |
152
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
NABORS INDUSTRIES LTD.
| By: |
/s/
Eugene
M. Isenberg
|
Eugene M. Isenberg
Chairman and
Chief Executive Officer
| By: |
/s/
R.
Clark Wood
|
R. Clark Wood
Principal accounting and
financial officer
Date: March 1, 2011
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
| Signature | Title | Date | ||||
|
/s/
Eugene
M. Isenberg
|
Chairman and Chief Executive Officer | March 1, 2011 | ||||
|
/s/
Anthony
G. Petrello
|
Deputy Chairman, President and Chief Operating Officer | March 1, 2011 | ||||
|
/s/
R.
Clark Wood
|
Principal accounting officer and principal financial officer | March 1, 2011 | ||||
|
/s/
William
T. Comfort
|
Director | March 1, 2011 | ||||
|
/s/
John
V. Lombardi
|
Director | March 1, 2011 | ||||
|
/s/
James
L. Payne
|
Director | March 1, 2011 | ||||
|
/s/
Myron
M. Sheinfeld
|
Director | March 1, 2011 | ||||
|
/s/
Martin
J. Whitman
|
Director | March 1, 2011 | ||||
|
/s/
John
Yearwood
|
Director | March 1, 2011 | ||||
153
Table of Contents
SCHEDULE II —
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
|
Balance at
|
Charged to
|
Charged to
|
Balance at
|
|||||||||||||||||
|
Beginning
|
Costs and
|
Other
|
End of
|
|||||||||||||||||
| of Period | Expenses | Accounts | Deductions | Period | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 23,681 | $ | 1,545 | $ | 167 | $ | (2,886 | ) | $ | 22,507 | |||||||||
|
Inventory reserve
|
4,824 | (182 | ) | 1,695 | 447 | 6,784 | ||||||||||||||
|
Valuation allowance on deferred tax assets
|
1,570,890 | — | — | (56,737 | ) | 1,514,153 | ||||||||||||||
|
2009
|
||||||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 23,224 | $ | 5,793 | $ | 239 | $ | (5,575 | ) | $ | 23,681 | |||||||||
|
Inventory reserve
|
4,483 | 1,429 | — | (1,088 | ) | 4,824 | ||||||||||||||
|
Valuation allowance on deferred tax assets
|
132,262 | 1,438,628 | — | — | 1,570,890 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 16,713 | $ | 6,715 | $ | 1,241 | $ | (1,445 | ) | $ | 23,224 | |||||||||
|
Inventory reserve
|
2,309 | 4,573 | — | (2,399 | ) | 4,483 | ||||||||||||||
|
Valuation allowance on deferred tax assets
|
29,658 | 102,604 | — | — | 132,262 | |||||||||||||||
154
Table of Contents
Exhibit Index
| Exhibits | Description | |||
| 12 | Computation of Ratios. | |||
| 21 | Significant Subsidiaries | |||
| 23 | .1 | Consent of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP — Houston. | ||
| 23 | .2 | Consent of Independent Auditors — Ernst & Young LLC — Houston. | ||
| 23 | .3 | Consent of Miller and Lents, Ltd. | ||
| 23 | .4 | Consent of Netherland, Sewell & Associates, Inc. | ||
| 23 | .5 | Consent of AJM Petroleum Consultants | ||
| 23 | .6 | Consent of Lonquist & Co., LLC | ||
| 23 | .7 | Consent of Miller and Lents, Ltd. — NFR Energy LLC | ||
| 31 | .1 | Rule 13a-14(a)/15d-14(a) Certification of Eugene M. Isenberg, Chairman and Chief Executive Officer | ||
| 31 | .2 | Rule 13a-14(a)/15d-14(a) Certification of R. Clark Wood, principal accounting and financial officer | ||
| 99 | .1 | Report of Miller and Lents, Ltd. | ||
| 99 | .2 | Report of Netherland, Sewell & Associates, Inc. | ||
| 99 | .3 | Report of AJM Petroleum Consultants | ||
| 99 | .4 | Report of Lonquist & Co., LLC | ||
| 99 | .5 | Report of Miller and Lents, Ltd. — NFR Energy LLC | ||
| 99 | .6 | Financial Statements and Notes for NFR Energy LLC | ||
155
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. (removed and Reserved)Part IIItem 5. Market For Registrant S Common Equity, Related Shareholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataNote 1 Nature Of OperationsNote 2 Summary Of Significant Accounting PoliciesNote 3 Impairments and Other ChargesNote 4 Cash and Cash Equivalents and InvestmentsNote 5 Fair Value MeasurementsNote 6 Share-based CompensationNote 7 Acquisitions and DivestituresNote 8 Property, Plant and EquipmentNote 9 Investments in Unconsolidated AffiliatesNote 10 Financial Instruments and Risk ConcentrationNote 11 DebtNote 12 Income TaxesNote 13 Common SharesNote 14 Subsidiary Preferred StockNote 15 Pension, Postretirement and Postemployment BenefitsNote 16 Related-party TransactionsNote 17 Commitments and ContingenciesNote 18 Earnings (losses) Per ShareNote 19 Supplemental Balance Sheet, Income Statement and Cash Flow InformationNote 20 Unaudited Quarterly Financial InformationNote 21 Discontinued OperationsNote 22 Segment InformationNote 23 Condensed Consolidating Financial InformationNote 24 Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited)Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Shareholder MattersItem 13. Certain Relationships and Related Transactions and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement Schedule