PATTERSON UTI ENERGY INC
10-Ks and 10-Qs
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Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C. 20549
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, 2009 | ||
|
or
|
||
|
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 0-22664
Patterson-UTI Energy,
Inc.
(Exact name of registrant as
specified in its charter)
|
Delaware
(State or other jurisdiction of incorporation or organization) |
75-2504748
(I.R.S. Employer Identification No.) |
|
|
450 Gears Road, Suite 500, Houston, Texas
(Address of principal executive offices) |
77067
(Zip Code) |
Registrant’s telephone number, including area code:
(281) 765-7100
Securities Registered Pursuant to Section 12(b) of the
Act:
|
Title of Each Class
|
Name of Exchange on Which Registered
|
|
|
Common Stock, $0.01 Par Value
|
The Nasdaq Global Select Market | |
|
Preferred Share Purchase Rights
|
The Nasdaq Global Select Market |
Securities
Registered Pursuant to Section 12(g) of the Act:
None
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
þ
or
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
or
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 (or for such shorter period
that the registrant was required to submit and post such
files). Yes
þ
or
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 definition of “large
accelerated filer,” “accelerated filer” and
“smaller reporting company” in
Rule 12b-2
of the Exchange Act.
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
o
No
þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant as of
June 30, 2009, the last business day of the
registrant’s most recently completed second fiscal quarter,
was $1,944,259,033, calculated by reference to the closing price
of $12.86 for the common stock on the Nasdaq Global Select
Market on that date.
As of February 17, 2010, the registrant had outstanding
153,567,174 shares of common stock, $.01 par value,
its only class of common stock.
Documents incorporated by reference:
Portions of the registrant’s definitive proxy statement for
the 2010 Annual Meeting of Stockholders are incorporated by
reference into Part III of this report.
Table of Contents
DISCLOSURE
REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on
Form 10-K
(this “Report”) and other public filings and press
releases by us contain “forward-looking statements”
within the meaning of the Securities Act of 1933, as amended
(the “Securities Act”), the Securities Exchange Act of
1934, as amended (the “Exchange Act”), and the Private
Securities Litigation Reform Act of 1995, as amended. These
“forward-looking statements” involve risk and
uncertainty. These forward-looking statements include, without
limitation, statements relating to: liquidity; financing of
operations; continued volatility of oil and natural gas prices;
source and sufficiency of funds required for immediate capital
needs and additional rig acquisitions (if further opportunities
arise); impact of inflation; demand for our services; and other
matters. Our forward-looking statements can be identified by the
fact that they do not relate strictly to historic or current
facts and often use words such as “believes,”
“budgeted,” “continue,” “expects,”
“estimates,” “project,” “will,”
“could,” “may,” “plans,”
“intends,” “strategy,” or
“anticipates,” or the negative thereof or other words
and expressions of similar meaning. The forward-looking
statements are based on certain assumptions and analyses we make
in light of our experience and our perception of historical
trends, current conditions, expected future developments and
other factors we believe are appropriate in the circumstances.
Although we believe that the expectations reflected in such
forward-looking statements are reasonable, we can give no
assurance that such expectations will prove to have been
correct. Forward-looking statements may be made orally or in
writing, including, but not limited to, Management’s
Discussion and Analysis of Financial Condition and Results of
Operations included in this Report and other sections of our
filings with the United States Securities and Exchange
Commission (the “SEC”) under the Exchange Act and the
Securities Act.
Forward-looking statements are not guarantees of future
performance and a variety of factors could cause actual results
to differ materially from the anticipated or expected results
expressed in or suggested by these forward-looking statements.
Factors that might cause or contribute to such differences
include, but are not limited to, deterioration of global
economic conditions, declines in oil and natural gas prices that
could adversely affect demand for our services and their
associated effect on day rates, rig utilization and planned
capital expenditures, excess availability of land drilling rigs,
including as a result of the reactivation or construction of new
land drilling rigs, adverse industry conditions, adverse credit
and equity market conditions, difficulty in integrating
acquisitions, demand for oil and natural gas, shortages of rig
equipment, governmental regulation and ability to retain
management and field personnel. Refer to “Risk
Factors” contained in Part 1 of this Report for a more
complete discussion of these and other factors that might affect
our performance and financial results. You are cautioned not to
place undue reliance on any of our forward-looking statements.
These forward-looking statements are intended to relay our
expectations about the future, and speak only as of the date
they are made. We undertake no obligation to publicly update or
revise any forward-looking statement, whether as a result of new
information, changes in internal estimates or otherwise.
| Item 1. | Business |
Available
Information
This Report, along with our 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 Exchange Act, are available
free of charge through our Internet website (www.patenergy.com)
as soon as reasonably practicable after we electronically file
such material with, or furnish it to, the SEC. The information
contained on our website is not part of this Report or other
filings that we make with the SEC. You may read and copy any
materials we file with the SEC at the SEC’s Public
Reference Room at 100 F Street, NE, Washington, DC
20549. You may obtain information on the operation of the Public
Reference Room by calling the SEC at
1-800-SEC-0330.
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.
1
Table of Contents
Overview
We own and operate one of the largest fleets of land-based
drilling rigs in the United States. The Company was formed in
1978 and reincorporated in 1993 as a Delaware corporation. Our
contract drilling business operates primarily in Texas, New
Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado,
Utah, Wyoming, Montana, North Dakota, Pennsylvania, West
Virginia and western Canada.
As of December 31, 2009, we had a drilling fleet that
consisted of 341 marketable land-based drilling rigs. A drilling
rig includes the structure, power source and machinery necessary
to cause a drill bit to penetrate the earth to a depth desired
by the customer. A drilling rig is considered marketable at a
point in time if it is operating or can be made ready to operate
without significant capital expenditures. We also have a
substantial inventory of drill pipe and drilling rig components.
We provide pressure pumping services to oil and natural gas
operators primarily in the Appalachian Basin. These services
consist primarily of well stimulation and cementing for
completion of new wells and remedial work on existing wells. We
also own and invest in oil and natural gas assets as a working
interest owner. Our oil and natural gas interests are located
primarily in Texas and New Mexico.
Prior to January 20, 2010, we provided drilling fluids,
completion fluids and related services to oil and natural gas
operators offshore in the Gulf of Mexico and on land in Texas,
New Mexico, Oklahoma and Louisiana. We exited the drilling and
completion fluids services business on January 20, 2010 and
sold substantially all of the assets, other than billed accounts
receivable, of that business.
Industry
Segments
Our revenues, operating profits and identifiable assets have
been primarily attributable to four industry segments:
| • | contract drilling services, | |
| • | pressure pumping services, | |
| • | oil and natural gas exploration and production, and. | |
| • | drilling and completion fluids services. |
On January 20, 2010, we exited the drilling and completion
fluids services business and ceased operations in that segment.
As a result of the sale of this business, the historical results
of operations for this segment have been reclassified and are
presented as discontinued operations in this Report.
All of our industry segments had operating profits in 2007. In
2008, except for our drilling and completion fluids services
segment, all of our industry segments had operating profits. In
2009, our pressure pumping services and oil and natural gas
exploration and production segments had operating profits and
our contract drilling services segment had an operating loss.
See “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” and Note 15 of
Notes to Consolidated Financial Statements included as a part of
Items 7 and 8, respectively, of this Report for financial
information pertaining to these industry segments.
Contract
Drilling Operations
General —
We market our contract drilling
services to major and independent oil and natural gas operators.
As of December 31, 2009, we had 341 marketable land-based
drilling rigs based in the following regions:
| • | 73 in west Texas and southeastern New Mexico, | |
| • | 100 in north central and east Texas, northern Louisiana and Mississippi, | |
| • | 56 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana and North Dakota), | |
| • | 49 in south Texas and southern Louisiana, |
2
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| • | 28 in the Texas panhandle, Oklahoma and Arkansas, | |
| • | 15 in the Appalachian Basin, and | |
| • | 20 in western Canada. |
Our marketable drilling rigs have rated maximum depth
capabilities ranging from 5,000 feet to 30,000 feet.
Of these drilling rigs, 107 are electric rigs and 234 are
mechanical rigs. An electric rig differs from a mechanical rig
in that the electric rig converts the diesel power (the sole
energy source for a mechanical rig) into electricity to power
the rig. We also have a substantial inventory of drill pipe and
drilling rig components, which may be used in the activation of
additional drilling rigs or as replacement parts for marketable
rigs.
Drilling rigs are typically equipped with engines, drawworks,
masts, pumps to circulate the drilling fluid, blowout
preventers, drill pipe and other related equipment. Over time,
components on a drilling rig are replaced or rebuilt. We spend
significant funds each year as part of a program to modify,
upgrade and maintain our drilling rigs to ensure that our
drilling equipment is competitive. We have spent
$1.3 billion during the last three years on capital
expenditures to (1) build new land drilling rigs and
(2) modify, upgrade and maintain our drilling fleet. During
fiscal years 2009, 2008 and 2007, we spent approximately
$395 million, $361 million and $540 million,
respectively, on these capital expenditures.
Depth and complexity of the well and drill site conditions are
the principal factors in determining the specifications of the
rig selected for a particular job.
Our contract drilling operations depend on the availability of
drill pipe, drill bits, replacement parts and other related rig
equipment, fuel and qualified personnel. Some of these have been
in short supply from time to time.
Drilling Contracts —
Most of our drilling
contracts are with established customers on a competitive bid or
negotiated basis. Our drilling contracts are either on a
well-to-well
basis or a term basis.
Well-to-well
contracts are generally short-term in nature and cover the
drilling of a single well or a series of wells. Term contracts
are entered into for a specified period of time (frequently one
to three years) and provide for the use of the drilling rig to
drill multiple wells. During 2009, our average number of days to
drill a well (which includes moving to the drill site, rigging
up and rigging down) was approximately 20 days.
Our drilling contracts obligate us to provide and operate a
drilling rig and to pay certain operating expenses, including
wages of drilling personnel and necessary maintenance expenses.
Most drilling contracts are subject to termination by the
customer on short notice and may or may not contain provisions
for the payment of an early termination fee to us in the event
that the contract is terminated by the customer. Generally, we
indemnify our customers against claims by our employees and
claims that might arise from surface pollution caused by spills
of fuel, lubricants and other solvents within our control.
Generally, the customers indemnify us against claims that might
arise from other surface and subsurface pollution. Each drilling
contract contains the actual terms setting forth our rights and
obligations and those of the customer, any of which rights and
obligations may deviate from what is customary due to industry
conditions or other factors.
Our drilling contracts provide for payment on a daywork,
footage, or turnkey basis, or a combination thereof. In each
case, we provide the rig and crews. Except for two wells drilled
under footage contracts in 2009, all of the wells drilled during
the years ended December 31, 2009, 2008 and 2007 were
drilled under daywork contracts. Our bid for each job depends
upon location, depth and anticipated complexity of the well,
on-site
drilling conditions, equipment to be used, estimated risks
involved, estimated duration of the job, availability of
drilling rigs and other factors particular to each proposed well.
Under daywork contracts, we provide the drilling rig and crew to
the customer. The customer supervises the drilling of the well.
Our compensation is based on a contracted rate per day during
the period the drilling rig is utilized. We often receive a
lower rate when the drilling rig is moving or when drilling
operations are interrupted or restricted by adverse weather
conditions or other conditions beyond our control. Daywork
contracts typically provide separately for mobilization of the
drilling rig. Except for two wells drilled under footage
contracts in 2009, all of the wells we drilled in 2009, 2008 and
2007 were under daywork contracts.
3
Table of Contents
Under footage contracts, we contract to drill a well to a
certain depth under specified conditions for a fixed price per
foot. The customer provides drilling fluids, casing, cementing
and well design expertise. These contracts require us to bear
the cost of services and supplies that we provide until the well
has been drilled to the agreed depth. If we drill the well in
less time than estimated, we have the opportunity to improve our
profits over those that would be attainable under a daywork
contract. Profits are reduced and losses may be incurred if the
well requires more days to drill to the contracted depth than
estimated. Footage contracts generally contain greater risks for
a drilling contractor than daywork contracts. Under footage
contracts, the drilling contractor typically assumes certain
risks associated with loss of the well from fire, blowouts and
other risks. We drilled two wells under footage contracts in
2009, and we did not drill any wells under footage contracts in
2008 or 2007.
Under turnkey contracts, we contract to drill a well to a
certain depth under specified conditions for a fixed fee. In a
turnkey arrangement, we are required to bear the costs of
services, supplies and equipment beyond those typically provided
under a footage contract. In addition to the drilling rig and
crew, we are required to provide the drilling and completion
fluids, casing, cementing, and the technical well design and
engineering services during the drilling process. We also
typically assume certain risks associated with drilling the well
such as fires, blowouts, cratering of the well bore and other
such risks. Compensation occurs only when the agreed scope of
the work has been completed, which requires us to make larger
up-front working capital commitments prior to receiving payments
under a turnkey drilling contract. Under a turnkey contract, we
have the opportunity to improve our profits if the drilling
process goes as expected and there are no complications or time
delays. Given the increased exposure we have under a turnkey
contract, however, profits can be significantly reduced and
losses can be incurred if complications or delays occur during
the drilling process. Turnkey contracts generally involve the
highest degree of risk among the three different types of
drilling contracts. Although we have entered into turnkey
contracts in the past, we did not enter into any turnkey
contracts in the past three years.
Contract Drilling Activity
— Information
regarding our contract drilling activity for the last three
years follows:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Average rigs operating per day(1)
|
91 | 254 | 244 | |||||||||
|
Number of rigs operated during the year
|
243 | 315 | 338 | |||||||||
|
Number of wells drilled during the year
|
1,539 | 4,218 | 4,237 | |||||||||
|
Number of operating days(2)
|
33,394 | 93,068 | 89,095 | |||||||||
| (1) | A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. | |
| (2) | Includes standby days under term contracts where revenue was earned but the rig was not working. The number of these standby days under term contracts was 2,070 in 2009, 486 in 2008 and zero in 2007. |
Drilling Rigs and Related Equipment
— We
estimate the depth capacity with respect to our marketable rigs
as of December 31, 2009 to be as follows:
| Number of Rigs | ||||||||||||
|
Depth Rating (Ft.)
|
U.S. | Canada | Total | |||||||||
|
5,000 to 7,999
|
— | 3 | 3 | |||||||||
|
8,000 to 11,999
|
59 | 9 | 68 | |||||||||
|
12,000 to 15,999
|
189 | 8 | 197 | |||||||||
|
16,000 to 30,000
|
73 | — | 73 | |||||||||
|
Totals
|
321 | 20 | 341 | |||||||||
At December 31, 2009, we owned and operated 323 trucks and
417 trailers used to rig down, transport and rig up our drilling
rigs. Our ownership of trucks and trailers reduces our
dependency upon third parties for these services and generally
enhances the efficiency of our contract drilling operations,
particularly in periods of high drilling rig utilization.
Most repair and overhaul work to our drilling rig equipment is
performed at our yard facilities located in Texas, Oklahoma,
Wyoming, Utah, Pennsylvania and western Canada.
4
Table of Contents
Pressure
Pumping Operations
General
— We provide pressure pumping services
to oil and natural gas operators primarily in the Appalachian
Basin. Pressure pumping services are primarily well stimulation
and cementing for the completion of new wells and remedial work
on existing wells. Most wells drilled in the Appalachian Basin
require some form of fracturing or other stimulation to enhance
the flow of oil and natural gas by pumping fluids under pressure
into the well bore. Appalachian Basin wells typically require
cementing services. The cementing process inserts material
between the wall of the well bore and the casing to center and
stabilize the casing.
Equipment
— Our pressure pumping equipment at
December 31, 2009 includes equipment used in providing
hydraulic and nitrogen fracturing services as well as cementing
services as follows:
Hydraulic fracturing equipment:
| • | 20 quintiplex pump trailers (45,000 hydraulic horsepower), | |
| • | 69 triplex pumper trucks (82,800 hydraulic horsepower), | |
| • | 35 blender trucks, | |
| • | 4 blender trailers, | |
| • | 32 bulk acid trucks/acid pumper trucks, | |
| • | 70 bulk sand trucks, | |
| • | 19 sand pneumatic trucks, | |
| • | 6 sand pneumatic trailers, | |
| • | 15 flatbed material trucks, | |
| • | 30 connection trucks, | |
| • | 1 shale fracturing hydration trailer, | |
| • | 3 shale fracturing manifold trailers, | |
| • | 1 shale fracturing iron trailer, | |
| • | 15 shale fracturing sand field bins with conveyors, and | |
| • | 3 shale fracturing large conveyors. |
Nitrogen fracturing equipment:
| • | 59 nitrogen pumper trucks (35,400 hydraulic horsepower), | |
| • | 30 bulk nitrogen trucks, and | |
| • | 9 bulk nitrogen tractor trailer combinations, |
Cementing equipment:
| • | 44 cement pumper trucks, and | |
| • | 51 bulk cement trucks. |
In addition to the equipment listed above, we had 45 tractors at
December 31, 2009 which are used in all of the lines of
business within our pressure pumping segment.
Oil and
Natural Gas Interests
We have been engaged in the development, exploration,
acquisition and production of oil and natural gas. Through
October 31, 2007, we served as operator with respect to
several properties and were actively involved in
5
Table of Contents
the development, exploration, acquisition and production of oil
and natural gas. Effective November 1, 2007, we sold the
related operations portion of our exploration and production
business, which was the portion of our business that actively
managed the development, exploration, acquisition and production
of oil and natural gas. We continue to own and invest in oil and
natural gas assets as a working interest owner. Our oil and
natural gas interests are located primarily in producing regions
of Texas and New Mexico.
Drilling
and Completion Fluids Operations
Prior to exiting the business in January 2010, we provided
drilling fluids, completion fluids and related services to oil
and natural gas operators offshore in the Gulf of Mexico and on
land in Texas, New Mexico, Oklahoma and Louisiana.
Customers
The customers of each of our oil and natural gas service
business segments are oil and natural gas operators. Our
customer base includes both major and independent oil and
natural gas operators. During 2009, no single customer accounted
for 10% or more of our consolidated operating revenues.
Competition
Our contract drilling and pressure pumping businesses are highly
competitive. Historically, available equipment used in these
businesses has frequently exceeded demand in our markets. The
price for our services is a key competitive factor in our
markets, in part because equipment used in our businesses can be
moved from one area to another in response to market conditions.
In addition to price, we believe availability and condition of
equipment, quality of personnel, service quality and safety
record are key factors in determining which contractor is
awarded a job in the markets in which we operate. We expect that
the market for land drilling and pressure pumping services will
continue to be competitive.
Government
and Environmental Regulation
All of our operations and facilities are subject to numerous
Federal, state, foreign, and local laws, rules and regulations
related to various aspects of our business, including:
| • | drilling of oil and natural gas wells, | |
| • | the relationships with our employees, | |
| • | containment and disposal of hazardous materials, oilfield waste, other waste materials and acids, | |
| • | use of underground storage tanks, and | |
| • | use of underground injection wells. |
To date, applicable environmental laws and regulations in the
United States and Canada have not required the expenditure of
significant resources outside the ordinary course of business.
We do not anticipate any material capital expenditures for
environmental control facilities or extraordinary expenditures
to comply with environmental rules and regulations in the
foreseeable future. However, compliance costs under existing
laws or under any new requirements could become material, and we
could incur liability in any instance of noncompliance.
Our business is generally affected by political developments and
by Federal, state, foreign, and local laws and regulations that
relate to the oil and natural gas industry. The adoption of laws
and regulations affecting the oil and natural gas industry for
economic, environmental and other policy reasons could increase
costs relating to drilling and production. They could have an
adverse effect on our operations. Federal, state, foreign and
local environmental laws and regulations currently apply to our
operations and may become more stringent in the future.
We believe we use operating and disposal practices that are
standard in the industry. However, hydrocarbons and other
materials may have been disposed of or released in or under
properties currently or formerly owned or operated by us or our
predecessors which may have resulted, or may result, in soil and
groundwater contamination in certain locations. Any
contamination found on, under or originating from the properties
may be subject to remediation requirements under Federal, state,
foreign and local laws and regulations. In addition, some of
these properties have been operated by third parties over whom
we have no control of their treatment of hydrocarbon and other
materials or the manner in which they may have disposed of or
released such materials. We could be required to remove or
remediate wastes disposed of or released by prior owners or
operators. In addition, it is possible we could be held
responsible for oil and natural gas properties in which we own
an interest but are not the operator.
6
Table of Contents
Some of the environmental laws and regulations that are
applicable to our business operations are discussed in the
following paragraphs, but the discussion does not cover all
environmental laws and regulations that govern our operations.
In the United States, the Federal Comprehensive Environmental
Response Compensation and Liability Act of 1980, as amended,
commonly known as CERCLA, and comparable state statutes impose
strict liability on:
| • | owners and operators of sites, and | |
| • | persons who disposed of or arranged for the disposal of “hazardous substances” found at sites. |
The Federal Resource Conservation and Recovery Act
(“RCRA”), as amended, and comparable state statutes
govern the disposal of “hazardous wastes.” Although
CERCLA currently excludes petroleum from the definition of
“hazardous substances,” and RCRA also excludes certain
classes of exploration and production wastes from regulation,
such exemptions by Congress under both CERCLA and RCRA may be
deleted, limited, or modified in the future. If such changes are
made to CERCLA
and/or
RCRA,
we could be required to remove and remediate previously disposed
of materials (including materials disposed of or released by
prior owners or operators) from properties (including ground
water contaminated with hydrocarbons) and to perform removal or
remedial actions to prevent future contamination.
The Federal Water Pollution Control Act and the Oil Pollution
Act of 1990, as amended, and implementing regulations govern:
| • | the prevention of discharges, including oil and produced water spills, and | |
| • | liability for drainage into waters. |
The Oil Pollution Act imposes strict liability for a
comprehensive and expansive list of damages from an oil spill
into waters from facilities. Liability may be imposed for oil
removal costs and a variety of public and private damages.
Penalties may also be imposed for violation of Federal safety,
construction and operating regulations, and for failure to
report a spill or to cooperate fully in a
clean-up.
The Oil Pollution Act also expands the authority and capability
of the Federal government to direct and manage oil spill
clean-up
and
operations, and requires operators to prepare oil spill response
plans in cases where it can reasonably be expected that
substantial harm will be done to the environment by discharges
on or into navigable waters. We have spill prevention control
and countermeasure plans in place for our working interest in
oil and natural gas properties in each of the areas in which
these interests are located. Failure to comply with ongoing
requirements or inadequate cooperation during a spill event may
subject a responsible party, such as us, to civil or criminal
actions. Although the liability for owners and operators is the
same under the Federal Water Pollution Act, the damages
recoverable under the Oil Pollution Act are potentially much
greater and can include natural resource damages.
In Canada, a variety of Canadian federal, provincial and
municipal laws and regulations impose, among other things,
restrictions, liabilities and obligations in connection with the
generation, handling, use, storage, transportation, treatment
and disposal of hazardous substances and wastes and in
connection with spills, releases and emissions of various
substances to the environment. These laws and regulations also
require that facility sites and other properties associated with
our operations be operated, maintained, abandoned and reclaimed
to the satisfaction of applicable regulatory authorities. In
addition, new projects or changes to existing projects may
require the submission and approval of environmental assessments
or permit applications. These laws and regulations are subject
to frequent change, and the clear trend is to place increasingly
stringent limitations on activities that may affect the
environment.
Our operations are also subject to Federal, state, foreign and
local laws, rules and regulations for the control of air
emissions, including the Federal Clean Air Act and the Canadian
Environmental Protection Act. We are aware of the increasing
focus of local, state, national and international regulatory
bodies on greenhouse gas (GHG) emissions and climate change
issues. We are also aware of legislation proposed by United
States lawmakers and the Canadian legislature to reduce GHG
emissions, as well as GHG emissions regulations enacted by the
U.S. Environmental Protection Agency and the Canadian
provinces of Alberta and British Columbia. We will continue to
monitor and assess any new policies, legislation or regulations
in the areas where we operate to determine the impact of GHG
emissions and climate change on our operations and take
appropriate actions, where necessary. Any direct and
7
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indirect costs of meeting these requirements may adversely
affect our business, results of operations and financial
condition.
Risks and
Insurance
Our operations are subject to the many hazards inherent in the
drilling business, including:
| • | accidents at the work location, | |
| • | blow-outs, | |
| • | cratering, | |
| • | fires, and | |
| • | explosions. |
These hazards could cause:
| • | personal injury or death, | |
| • | suspension of drilling operations, or | |
| • | serious damage or destruction of the equipment involved and, in addition to environmental damage, could cause substantial damage to producing formations and surrounding areas. |
Damage to the environment, including property contamination in
the form of either soil or ground water contamination, could
also result from our operations, particularly through:
| • | oil or produced water spillage, | |
| • | natural gas leaks, and | |
| • | fires. |
In addition, we could become subject to liability for reservoir
damages. The occurrence of a significant event, including
pollution or environmental damages, could materially affect our
operations, cash flows and financial condition.
As a protection against operating hazards, we maintain insurance
coverage we believe to be adequate, including:
| • | insurance for fire, windstorm and other risks of physical loss to our rigs and other assets, | |
| • | employer’s liability, | |
| • | automobile liability, | |
| • | commercial general liability insurance, and | |
| • | workers compensation insurance. |
We believe that we are adequately insured for bodily injury and
property damage to others with respect to our operations. Such
insurance, however, may not be sufficient to protect us against
liability for all consequences of:
| • | personal injury, | |
| • | well disasters, | |
| • | extensive fire damage, | |
| • | damage to the environment, or | |
| • | other hazards. |
We also carry insurance to cover physical damage to, or loss of,
our drilling rigs. Such insurance does not, however, cover the
full replacement cost of the rigs, and we do not carry insurance
against loss of earnings resulting
8
Table of Contents
from such damage. In view of the difficulties that may be
encountered in renewing such insurance at reasonable rates, no
assurance can be given that:
| • | we will be able to maintain the type and amount of coverage that we believe to be adequate at reasonable rates, or | |
| • | any particular types of coverage will be available. |
In addition to insurance coverage, we also attempt to obtain
indemnification from our customers for certain risks. These
indemnity agreements typically require our customers to hold us
harmless in the event of loss of production or reservoir damage.
These contractual indemnifications, if obtained, may not be
supported by adequate insurance maintained by the customer.
Employees
We had approximately 4,200 full-time employees at
December 31, 2009. The number of employees fluctuates
depending on the current and expected demand for our services.
We consider our employee relations to be satisfactory. None of
our employees are represented by a union.
Seasonality
Seasonality does not significantly affect our overall
operations. However, our drilling operations in Canada and, to a
lesser extent, our pressure pumping operations in the
Appalachian Basin, are subject to slow periods of activity
during the Spring thaw.
Raw
Materials and Subcontractors
We use many suppliers of raw materials and services. These
materials and services have historically been available,
although there is no assurance that such materials and services
will continue to be available on favorable terms or at all. We
also utilize numerous independent subcontractors from various
trades.
| Item 1A. | Risk Factors. |
You should consider each of the following factors as well as the
other information in this Report in evaluating our business and
our prospects. Additional risks and uncertainties not presently
known to us or that we currently consider immaterial may also
impair our business operations. If any of the following risks
actually occur, our business and financial results could be
harmed. You should also refer to the other information set forth
in this Report, including our financial statements and the
related notes.
Global
Economic Conditions May Adversely Affect Our Operating
Results.
Since reaching a peak in June 2008, there has been a significant
decline in oil and natural gas prices. Since that time there has
also been a significant deterioration in the global economic
environment. As part of this deterioration, there has been
significant uncertainty in the capital markets and access to
financing has been reduced. Due to these conditions, our
customers reduced or curtailed their drilling programs, which
resulted in a decrease in demand for our services. Furthermore,
these factors have resulted in, and could continue to result in,
certain of our customers experiencing an inability to pay
suppliers, including us, if they are not able to access capital
to fund their operations. Although the significant deterioration
in the global economic environment appears to have recently
stabilized to some degree, our customers may not substantially
increase their drilling programs unless there is more certainty
about global economic prospects. These conditions could have a
material adverse effect on our business, financial condition,
cash flows and results of operations.
9
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We are
Dependent on the Oil and Natural Gas Industry and Market Prices
for Oil and Natural Gas. Declines in Oil and Natural Gas Prices
Have Adversely Affected Our Operating Results.
Our revenue, profitability, financial condition and rate of
growth are substantially dependent upon prevailing prices for
natural gas and, to a lesser extent, oil. For many years, oil
and natural gas prices and markets have been extremely volatile.
Prices are affected by:
| • | market supply and demand, | |
| • | international military, political and economic conditions, and | |
| • | the ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets. |
All of these factors are beyond our control. During 2008, the
monthly average market price of natural gas peaked in June at
$13.06 per Mcf before rapidly declining to an average of $5.99
per Mcf in December 2008. In 2009, the monthly average market
price of natural gas declined further to a low of $3.06 per Mcf
in September. This decline in the market price of natural gas
resulted in our customers significantly reducing their drilling
activities beginning in the fourth quarter of 2008, and drilling
activities remained low throughout 2009. This reduction in
demand combined with the reactivation and construction of new
land drilling rigs in the United States during the last several
years has resulted in excess capacity compared to demand. As a
result of these factors, our average number of rigs operating
has declined significantly. We expect oil and natural gas prices
to continue to be volatile and to affect our financial
condition, operations and ability to access sources of capital.
Low market prices for natural gas would likely result in demand
for our drilling rigs remaining low and adversely affect our
operating results, financial condition and cash flows.
A
General Excess of Operable Land Drilling Rigs and Increasing Rig
Specialization May Adversely Affect Our Utilization and Profit
Margins.
The North American land drilling industry has experienced
periods of downturn in demand over the last decade. During these
periods, there have been substantially more drilling rigs
available than necessary to meet demand. As a result, drilling
contractors have had difficulty sustaining profit margins and,
at times, have sustained losses during the downturn periods.
In addition, unconventional resource plays have substantially
increased recently and some drilling rigs are not capable of
drilling these wells efficiently. Accordingly, the utilization
of some older technology drilling rigs may be hampered by their
lack of capability to successfully compete for this work. Other
ongoing factors which could continue to adversely affect
utilization rates and pricing, even in an environment of high
oil and natural gas prices and increased drilling activity,
include:
| • | movement of drilling rigs from region to region, | |
| • | reactivation of land-based drilling rigs, or | |
| • | construction of new drilling rigs. |
Construction of new drilling rigs increased significantly during
the last five years. The addition of new drilling rigs to the
market and the recent decrease in demand has resulted in excess
capacity. We cannot predict either the future level of demand
for our contract drilling services or future conditions in the
oil and natural gas contract drilling business.
Shortages
of Drill Pipe, Replacement Parts and Other Related Rig Equipment
Adversely Affects Our Operating Results.
During periods of increased demand for drilling services, the
industry has experienced shortages of drill pipe, replacement
parts and other related rig equipment. These shortages can cause
the price of these items to increase significantly and require
that orders for the items be placed well in advance of expected
use. In addition, any interruption in supply due to vendor or
other issues could result in significant delays in delivery of
equipment. These
10
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price increases and delays in delivery may require us to
increase capital and repair expenditures in our contract
drilling segment. Severe shortages or delays in delivery could
limit our ability to operate our drilling rigs.
The
Oil Service Business Segments in Which We Operate Are Highly
Competitive with Excess Capacity, which Adversely Affects Our
Operating Results.
Our land drilling and pressure pumping businesses are highly
competitive. At times, available land drilling rigs and pressure
pumping equipment exceed the demand for such equipment. This
excess capacity has resulted in substantial competition for
drilling and pressure pumping contracts. The fact that drilling
rigs and pressure pumping equipment are mobile and can be moved
from one market to another in response to market conditions
heightens the competition in the industry.
We believe that price competition for drilling and pressure
pumping contracts will continue due to the existence of
available rigs and pressure pumping equipment.
In recent years, many drilling and pressure pumping companies
have consolidated or merged with other companies. Although this
consolidation has decreased the total number of competitors, we
believe the competition for drilling and pressure pumping
services will continue to be intense.
Labor
Shortages and Rising Labor Costs Adversely Affect Our Operating
Results.
During periods of increasing demand for contract drilling and
pressure pumping services, the industry experiences shortages of
qualified personnel. During these periods, our ability to
attract and retain sufficient qualified personnel to market and
operate our drilling rigs and pressure pumping equipment is
adversely affected, which negatively impacts both our operations
and profitability. Operationally, it is more difficult to hire
qualified personnel, which adversely affects our ability to
mobilize inactive rigs and pressure pumping equipment in
response to the increased demand for such services.
Additionally, wage rates for drilling and pressure pumping
personnel are likely to increase during periods of increasing
demand, resulting in higher operating costs.
Growth
Through the Building of New Rigs and Rig Acquisitions are Not
Assured.
We have increased our drilling rig fleet in the past through
mergers, acquisitions and rig construction. The land drilling
industry has experienced significant consolidation, and there
can be no assurance that acquisition opportunities will be
available in the future. We are also likely to continue to face
intense competition from other companies for available
acquisition opportunities. In addition, because improved
technology has enhanced the ability to recover oil and natural
gas, contract drillers may continue to build new, high
technology rigs.
There can be no assurance that we will:
| • | have sufficient capital resources to complete additional acquisitions or build new rigs, | |
| • | successfully integrate additional drilling rigs or other assets, | |
| • | effectively manage the growth and increased size of our organization and drilling fleet, | |
| • | successfully deploy idle, stacked or additional rigs, | |
| • | maintain the crews necessary to operate additional drilling rigs, or | |
| • | successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition or the building of new drilling rigs. |
We may incur substantial indebtedness to finance future
acquisitions or build new drilling rigs and also may issue
equity, convertible or debt securities in connection with any
such acquisitions or building program. Debt service requirements
could represent a significant burden on our results of
operations and financial condition, and the issuance of
additional equity would be dilutive to existing stockholders.
Also, continued growth could strain our management, operations,
employees and other resources.
11
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The
Nature of our Business Operations Presents Inherent Risks of
Loss that, if not Insured or Indemnified Against, Could
Adversely Affect Our Operating Results.
Our operations are subject to many hazards inherent in the
contract drilling and pressure pumping businesses, which in turn
could cause personal injury or death, work stoppage, or serious
damage to our equipment. Our operations could also cause
environmental and reservoir damages. We maintain insurance
coverage and have indemnification agreements with many of our
customers. However, there is no assurance that such insurance or
indemnification agreements would adequately protect us against
liability or losses from all consequences of these hazards.
Additionally, there can be no assurance that insurance would be
available to cover any or all of these risks, or, even if
available, that insurance premiums or other costs would not rise
significantly in the future, so as to make the cost of such
insurance prohibitive. Incurring a liability for which we are
not fully insured or indemnified could materially affect our
business, financial condition and results of operations.
We have also elected in some cases to accept a greater amount of
risk through increased deductibles on certain insurance
policies. For example, we maintain a $1.0 million per
occurrence deductible on our workers’ compensation, general
liability and equipment insurance coverages.
Violations
of Environmental Laws and Regulations Could Materially Adversely
Affect Our Operating Results.
All of our operations and facilities are subject to numerous
Federal, state, foreign and local environmental laws, rules and
regulations, including, without limitation, laws concerning the
containment and disposal of hazardous substances, oil field
waste and other waste materials, the use of underground storage
tanks, and the use of underground injection wells. The cost of
compliance with these laws and regulations could be substantial.
A failure to comply with these requirements could expose us to
substantial civil and criminal penalties. In addition,
environmental laws and regulations in the United States and
Canada impose a variety of requirements on “responsible
parties” related to the prevention of oil spills and
liability for damages from such spills. As an owner and operator
of land-based drilling rigs, we may be deemed to be a
responsible party under these laws and regulations.
We are aware of the increasing focus of local, state, national
and international regulatory bodies on GHG emissions and climate
change issues. We are also aware of legislation proposed by
United States lawmakers and the Canadian legislature to reduce
GHG emissions, as well as GHG emissions regulations enacted by
the U.S. Environmental Protection Agency and the Canadian
provinces of Alberta and British Columbia. We will continue to
monitor and assess any new policies, legislation or regulations
in the areas where we operate to determine the impact of GHG
emissions and climate change on our operations and take
appropriate actions, where necessary. Any direct and indirect
costs of meeting these requirements may adversely affect our
business, results of operations and financial condition.
Anti-takeover
Measures in Our Charter Documents and Under State Law Could
Discourage an Acquisition and Thereby Affect the Related
Purchase Price.
We are a Delaware corporation subject to the Delaware General
Corporation Law, including Section 203, an anti-takeover
law. We have also enacted certain anti-takeover measures,
including a stockholders’ rights plan. In addition, our
Board of Directors has the authority to issue up to one million
shares of preferred stock and to determine the price, rights
(including voting rights), conversion ratios, preferences and
privileges of that stock without further vote or action by the
holders of the common stock. As a result of these measures and
others, potential acquirers might find it more difficult or be
discouraged from attempting to effect an acquisition transaction
with us. This may deprive holders of our securities of certain
opportunities to sell or otherwise dispose of the securities at
above-market prices pursuant to any such transactions.
| Item 1B. | Unresolved Staff Comments. |
None.
12
Table of Contents
| Item 2. | Properties |
Our corporate headquarters comprises approximately
12,000 square feet of leased office space, and is located
at 450 Gears Road, Suite 500, Houston, Texas. Our telephone
number at that address is
(281) 765-7100.
Our primary administrative office is located in Snyder, Texas
and includes approximately 37,000 square feet of office and
storage space.
Contract Drilling Operations
— Our drilling
services are supported by several offices and yard facilities
located throughout our areas of operations, including Texas, New
Mexico, Oklahoma, Colorado, Utah, Wyoming, Pennsylvania and
western Canada.
Pressure Pumping
— Our pressure pumping
services are supported by several offices and yard facilities
located throughout our areas of operations including
Pennsylvania, Ohio, New York, West Virginia, Kentucky, Tennessee
and Colorado.
Oil and Natural Gas Working Interests
— Our
interests in oil and natural gas properties are primarily
located in Texas and New Mexico.
We own our administrative offices in Snyder, Texas, as well as
several of our other facilities. We also lease a number of
facilities, and we do not believe that any one of the leased
facilities is individually material to our operations. We
believe that our existing facilities are suitable and adequate
to meet our needs.
| Item 3. | Legal Proceedings. |
We are party to various legal proceedings arising in the normal
course of our business. We do not believe that the outcome of
these proceedings, either individually or in the aggregate, will
have a material adverse effect on our results of operations,
cash flows or financial condition.
| Item 4. | Submission of Matters to a Vote of Security Holders. |
None.
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| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
| (a) | Market Information |
Our common stock, par value $0.01 per share, is publicly traded
on the Nasdaq Global Select Market and is quoted under the
symbol “PTEN.” Our common stock is included in the
S&P MidCap 400 Index and several other market indices. The
following table provides high and low sales prices of our common
stock for the periods indicated:
| High | Low | |||||||
|
2008:
|
||||||||
|
First quarter
|
$ | 26.38 | $ | 17.40 | ||||
|
Second quarter
|
36.40 | 25.71 | ||||||
|
Third quarter
|
37.45 | 17.85 | ||||||
|
Fourth quarter
|
19.64 | 8.64 | ||||||
|
2009:
|
||||||||
|
First quarter
|
$ | 13.50 | $ | 7.49 | ||||
|
Second quarter
|
15.95 | 8.56 | ||||||
|
Third quarter
|
15.98 | 11.38 | ||||||
|
Fourth quarter
|
18.07 | 14.20 | ||||||
| (b) | Holders |
As of February 17, 2010, there were approximately 1,700 holders
of record of our common stock.
| (c) | Dividends |
We paid cash dividends during the years ended December 31,
2008 and 2009 as follows:
| Per Share | Total | |||||||
| (in thousands) | ||||||||
|
2008:
|
||||||||
|
Paid on March 28, 2008
|
$ | 0.12 | $ | 18,493 | ||||
|
Paid on June 27, 2008
|
0.16 | 25,011 | ||||||
|
Paid on September 29, 2008
|
0.16 | 24,803 | ||||||
|
Paid on December 29, 2008
|
0.16 | 24,558 | ||||||
|
Total cash dividends
|
$ | 0.60 | $ | 92,865 | ||||
|
2009:
|
||||||||
|
Paid on March 31, 2009
|
$ | 0.05 | $ | 7,655 | ||||
|
Paid on June 30, 2009
|
0.05 | 7,675 | ||||||
|
Paid on September 30, 2009
|
0.05 | 7,675 | ||||||
|
Paid on December 30, 2009
|
0.05 | 7,676 | ||||||
|
Total cash dividends
|
$ | 0.20 | $ | 30,681 | ||||
On February 10, 2010, our Board of Directors approved a
cash dividend on our common stock in the amount of $0.05 per
share to be paid on March 30, 2010 to holders of record as
of March 15, 2010. The amount and timing of all future
dividend payments, if any, is subject to the discretion of the
Board of Directors and will depend upon business conditions,
results of operations, financial condition, terms of our credit
facilities and other factors.
14
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| (d) | Securities Authorized for Issuance Under Equity Compensation Plans |
Equity compensation plan information as of December 31,
2009 follows:
| Equity Compensation Plan Information | ||||||||||||
|
Number of
|
||||||||||||
|
Number of
|
Securities
|
|||||||||||
|
Securities to
|
Remaining Available
|
|||||||||||
|
be Issued upon
|
for Future Issuance
|
|||||||||||
|
Exercise of
|
Weighted-Average
|
under Equity
|
||||||||||
|
Outstanding
|
Exercise Price
|
Compensation Plans
|
||||||||||
|
Options,
|
of Outstanding
|
(Excluding Securities
|
||||||||||
|
Warrants and
|
Options, Warrants
|
Reflected in
|
||||||||||
|
Plan Category
|
Rights | and Rights | Column(a)) | |||||||||
| (a) | (b) | (c) | ||||||||||
|
Equity compensation plans approved by security holders(1)
|
6,627,634 | $ | 20.50 | 2,545,524 | ||||||||
|
Equity compensation plans not approved by security holders(2)
|
214,136 | $ | 9.97 | — | ||||||||
|
Total
|
6,841,770 | $ | 20.17 | 2,545,524 | ||||||||
| (1) | The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended (the “2005 Plan”), provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents to key employees, officers and directors, which are subject to certain vesting and forfeiture provisions. All options are granted with an exercise price equal to or greater than the fair market value of the common stock at the time of grant. The vesting schedule and term are set by the Compensation Committee of the Board of Directors. All securities remaining available for future issuance under equity compensation plans approved by security holders in column (c) are available under this plan. | |
| (2) | The Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (the “2001 Plan”) was approved by the Board of Directors in July 2001. In connection with the approval of the 2005 Plan, the Board of Directors approved a resolution that no further options, restricted stock or other awards would be granted under any equity compensation plan, other than the 2005 Plan. The terms of the 2001 Plan provided for grants of stock options, stock appreciation rights, shares of restricted stock and performance awards to eligible employees other than officers and directors. No Incentive Stock Options could be awarded under the 2001 Plan. All options were granted with an exercise price equal to or greater than the fair market value of the common stock at the time of grant. The vesting schedule and term were set by the Compensation Committee of the Board of Directors. |
15
Table of Contents
| (e) | Performance Graph |
The following graph compares the cumulative stockholder return
of our common stock for the period from December 31, 2004
through December 31, 2009, with the cumulative total return
of the Standard & Poors 500 Stock Index, the
Standard & Poors MidCap Index, the Oilfield Service
Index and a peer group determined by us. Our 2008 peer group
consists of BJ Services Company, Bronco Drilling Company, Inc.,
Helmerich & Payne, Inc., Nabors Industries, Ltd.,
Pioneer Drilling Co., Superior Well Services, Inc. and Unit
Corp. We evaluated our peer group for 2009 and determined that
it was appropriate to remove Unit Corp. from the peer group as
their drilling revenue as a percentage of total revenue had
fallen to a level that was no longer comparable to ours. All of
the companies in our peer group are providers of land-based
drilling or pressure pumping services. The graph assumes
investment of $100 on December 31, 2004 and reinvestment of
all dividends.
| Fiscal Year Ended December 31, | ||||||||||||||||||||||||
|
2004
|
2005
|
2006
|
2007
|
2008
|
2009
|
|||||||||||||||||||
|
Company/Index
|
($) | ($) | ($) | ($) | ($) | ($) | ||||||||||||||||||
|
Patterson-UTI Energy, Inc.
|
100.00 | 170.35 | 121.41 | 104.04 | 63.26 | 85.73 | ||||||||||||||||||
|
2008 Peer Group Index
|
100.00 | 155.75 | 125.07 | 117.78 | 58.99 | 94.96 | ||||||||||||||||||
|
2009 Peer Group Index
|
100.00 | 156.66 | 124.84 | 117.42 | 57.93 | 93.38 | ||||||||||||||||||
|
S&P 500 Stock Index
|
100.00 | 104.91 | 121.48 | 128.16 | 80.74 | 102.11 | ||||||||||||||||||
|
Oilfield Service Index (OSX)
|
100.00 | 149.90 | 171.09 | 251.13 | 102.21 | 164.12 | ||||||||||||||||||
|
S&P MidCap Index
|
100.00 | 112.56 | 124.17 | 134.08 | 85.50 | 117.46 | ||||||||||||||||||
The foregoing graph is based on historical data and is not
necessarily indicative of future performance. This graph shall
not be deemed to be “soliciting material” or to be
“filed” with the SEC or subject to Regulations 14A or
14C under the Exchange Act or to the liabilities of
Section 18 under such Act.
| Item 6. | Selected Financial Data. |
Our selected consolidated financial data as of December 31,
2009, 2008, 2007, 2006 and 2005, and for each of the five years
in the period ended December 31, 2009 should be read in
conjunction with “Management’s Discussion and Analysis
of Financial Condition and Results of Operations” and the
Consolidated Financial Statements and related Notes thereto,
included as Items 7 and 8, respectively, of this Report.
Certain reclassifications have been made to the historical
financial data to conform with the 2009 presentation. Due to the
sale of
16
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substantially all of the assets of our drilling and completion
fluids business in January 2010, the results of operations for
that business have been reclassified and are presented as
discontinued operations in all periods presented below.
| Years Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||
|
Statement of Operations Data:
|
||||||||||||||||||||
|
Operating revenues:
|
||||||||||||||||||||
|
Contract drilling
|
$ | 599,287 | $ | 1,804,026 | $ | 1,741,647 | $ | 2,169,370 | $ | 1,485,684 | ||||||||||
|
Pressure pumping
|
161,441 | 217,494 | 202,812 | 145,671 | 93,144 | |||||||||||||||
|
Oil and natural gas
|
21,218 | 42,360 | 41,637 | 39,187 | 39,616 | |||||||||||||||
|
Total
|
781,946 | 2,063,880 | 1,986,096 | 2,354,228 | 1,618,444 | |||||||||||||||
|
Operating costs and expenses:
|
||||||||||||||||||||
|
Contract drilling
|
357,742 | 1,038,327 | 963,150 | 1,002,001 | 776,313 | |||||||||||||||
|
Pressure pumping
|
111,414 | 132,570 | 105,273 | 77,755 | 54,956 | |||||||||||||||
|
Oil and natural gas
|
7,341 | 12,793 | 10,864 | 13,374 | 9,566 | |||||||||||||||
|
Depreciation, depletion and impairment
|
289,847 | 275,990 | 246,346 | 193,664 | 154,025 | |||||||||||||||
|
Selling, general and administrative
|
56,621 | 58,080 | 54,665 | 44,544 | 30,198 | |||||||||||||||
|
Embezzlement costs (recoveries)
|
— | — | (43,955 | ) | 3,081 | 20,043 | ||||||||||||||
|
Net loss (gain) on asset disposals
|
3,385 | (4,163 | ) | (16,432 | ) | 3,905 | (1,200 | ) | ||||||||||||
|
Other operating expenses
|
3,810 | 4,350 | 2,875 | 5,585 | 4,859 | |||||||||||||||
|
Total
|
830,160 | 1,517,947 | 1,322,786 | 1,343,909 | 1,048,760 | |||||||||||||||
|
Operating income (loss)
|
(48,214 | ) | 545,933 | 663,310 | 1,010,319 | 569,684 | ||||||||||||||
|
Other income (expense)
|
(3,341 | ) | 1,425 | 527 | 4,657 | 3,465 | ||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
(51,555 | ) | 547,358 | 663,837 | 1,014,976 | 573,149 | ||||||||||||||
|
Income tax expense (benefit)
|
(17,595 | ) | 193,490 | 229,350 | 360,639 | 207,706 | ||||||||||||||
|
Income (loss) from continuing operations
|
$ | (33,960 | ) | $ | 353,868 | $ | 434,487 | $ | 654,337 | $ | 365,443 | |||||||||
|
Income (loss) from continuing operations per common share:
|
||||||||||||||||||||
|
Basic
|
$ | (0.22 | ) | $ | 2.29 | $ | 2.78 | $ | 3.94 | $ | 2.14 | |||||||||
|
Diluted
|
$ | (0.22 | ) | $ | 2.27 | $ | 2.75 | $ | 3.89 | $ | 2.11 | |||||||||
|
Cash dividends per common share
|
$ | 0.20 | $ | 0.60 | $ | 0.44 | $ | 0.28 | $ | 0.16 | ||||||||||
|
Weighted average number of common shares outstanding:
|
||||||||||||||||||||
|
Basic
|
152,069 | 153,379 | 154,755 | 165,159 | 170,426 | |||||||||||||||
|
Diluted
|
152,069 | 154,358 | 156,612 | 167,200 | 172,312 | |||||||||||||||
|
Balance Sheet Data:
|
||||||||||||||||||||
|
Total assets
|
$ | 2,662,152 | $ | 2,712,817 | $ | 2,465,199 | $ | 2,192,503 | $ | 1,795,781 | ||||||||||
|
Borrowings under line of credit
|
— | — | 50,000 | 120,000 | — | |||||||||||||||
|
Stockholders’ equity
|
2,081,700 | 2,126,942 | 1,896,030 | 1,562,466 | 1,367,011 | |||||||||||||||
|
Working capital
|
263,960 | 338,761 | 227,577 | 335,052 | 382,448 | |||||||||||||||
17
Table of Contents
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Management Overview
— We are a leading provider
of contract services to the North American oil and natural gas
industry. Our services primarily involve the drilling, on a
contract basis, of land-based oil and natural gas wells and, to
a lesser extent, pressure pumping services. In addition to the
aforementioned contract services, we also invest, on a working
interest basis, in oil and natural gas properties. For the three
years ended December 31, 2009, our operating revenues
consisted of the following (dollars in thousands):
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
|
Contract drilling
|
$ | 599,287 | 76 | % | $ | 1,804,026 | 87 | % | $ | 1,741,647 | 88 | % | ||||||||||||
|
Pressure pumping
|
161,441 | 21 | 217,494 | 11 | 202,812 | 10 | ||||||||||||||||||
|
Oil and natural gas
|
21,218 | 3 | 42,360 | 2 | 41,637 | 2 | ||||||||||||||||||
| $ | 781,946 | 100 | % | $ | 2,063,880 | 100 | % | $ | 1,986,096 | 100 | % | |||||||||||||
We provide our contract services to oil and natural gas
operators in many of the oil and natural gas producing regions
of North America. Our contract drilling operations are focused
in various regions of Texas, New Mexico, Oklahoma, Arkansas,
Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North
Dakota, South Dakota, Pennsylvania, and western Canada, while
our pressure pumping services are focused primarily in the
Appalachian Basin. The oil and natural gas properties in which
we hold interests are primarily located in Texas and New Mexico.
Typically, the profitability of our business is most readily
assessed by two primary indicators in our contract drilling
segment: our average number of rigs operating and our average
revenue per operating day. During 2009, our average number of
rigs operating was 91 compared to 254 in 2008 and 244 in 2007.
Our average revenue per operating day was $17,950 in 2009
compared to $19,380 in 2008 and $19,550 in 2007. We had a
consolidated net loss of $38.3 million for 2009 compared to
consolidated net income of $347 million for 2008. This
decrease was primarily due to our contract drilling segment
experiencing a significant decrease in the average number of
rigs operating as compared to 2008.
Our revenues, profitability and cash flows are highly dependent
upon prevailing prices for natural gas and, to a lesser extent,
oil. During periods of improved commodity prices, the capital
spending budgets of oil and natural gas operators tend to
expand, which generally results in increased demand for our
contract services. Conversely, in periods when these commodity
prices deteriorate, the demand for our contract services
generally weakens and we experience downward pressure on pricing
for our services. Since reaching a peak in June 2008, there has
been a significant decline in oil and natural gas prices. Since
that time there has also been a substantial deterioration in the
global economic environment. As part of this deterioration,
there has been substantial uncertainty in the capital markets
and access to financing has been reduced. Due to these
conditions, our customers reduced or curtailed their drilling
programs, which resulted in a decrease in demand for our
services, as evidenced by the decline in our monthly average
rigs operating from a high of 283 in October 2008 to a low of 60
in June 2009 before partially recovering to 118 in December
2009. Furthermore, these factors have resulted in, and could
continue to result in, certain of our customers experiencing an
inability to pay suppliers, including us, if they are not able
to access capital to fund their operations. We are also highly
impacted by competition, the availability of excess equipment,
labor issues and various other factors that could materially
adversely affect our business, financial condition, cash flows
and results of operations and which are more fully described
above as “Risk Factors” in Item 1A of this Report.
We believe that the liquidity shown on our balance sheet as of
December 31, 2009, which includes approximately
$264 million in working capital (including
$49.9 million in cash) and approximately $194 million
available under our $240 million revolving credit facility,
together with cash expected to be generated from operations
(including expected income tax refunds in 2010 of approximately
$114 million resulting from the carry-back of net operating
losses), should provide us with sufficient ability to fund our
current plans to build new equipment, make improvements to our
existing equipment, expand into new regions, pay cash dividends
and survive the current downturn in our industry. If we pursue
opportunities for growth that require capital, we believe we
would be able to satisfy these needs through a combination of
working capital, cash generated from operations, borrowing
capacity under our revolving credit facility or additional debt
or equity financing. However, there can be no assurance that
such capital will be available on reasonable terms, if at all.
18
Table of Contents
Commitments and Contingencies
— As of
December 31, 2009, we maintained letters of credit in the
aggregate amount of $46.3 million for the benefit of
various insurance companies as collateral for retrospective
premiums and retained losses which could become payable under
the terms of the underlying insurance contracts. These letters
of credit expire at various times during each calendar year and
are typically renewed annually. As of December 31, 2009, no
amounts had been drawn under the letters of credit.
As of December 31, 2009, we had commitments to purchase
approximately $186 million of major equipment.
Trading and investing
— We have not engaged in
trading activities that include high-risk securities, such as
derivatives and non-exchange traded contracts. We invest cash
primarily in highly liquid, short-term investments such as
overnight deposits and money market accounts.
Description of business
— We conduct our
contract drilling operations in Texas, New Mexico, Oklahoma,
Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming,
Montana, North Dakota, Pennsylvania, West Virginia and western
Canada. For the years ended December 31, 2009, 2008 and
2007, revenue earned in Canada was $45.4 million,
$88.5 million and $72.9 million, respectively.
Additionally, we had long-lived assets located in Canada of
$69.2 million and $67.2 million as of
December 31, 2009 and 2008, respectively. As of
December 31, 2009, we had 341 marketable land-based
drilling rigs. We provide pressure pumping services to oil and
natural gas operators primarily in the Appalachian Basin. These
services consist primarily of well stimulation and cementing for
completion of new wells and remedial work on existing wells.
Prior to the sale of substantially all of the assets of our
drilling fluids business on January 20, 2010, we provided
drilling fluids, completion fluids and related services to oil
and natural gas operators offshore in the Gulf of Mexico and on
land in Texas, New Mexico, Oklahoma and Louisiana. Drilling and
completion fluids are used by oil and natural gas operators
during the drilling process to control pressure when drilling
oil and natural gas wells. Due to our exit from the drilling and
completion fluids business in January 2010, we have presented
the results of that operating segment as discontinued operations
in this Report. We also invest, on a working interest basis, in
oil and natural gas properties.
Critical
Accounting Policies
In addition to established accounting policies, our consolidated
financial statements are impacted by certain estimates and
assumptions made by management. The following is a discussion of
our critical accounting policies pertaining to property and
equipment, oil and natural gas properties, goodwill, revenue
recognition and the use of estimates.
Property and equipment
— Property and
equipment, including betterments which extend the useful life of
the asset, are stated at cost. Maintenance and repairs are
charged to expense when incurred. We provide for the
depreciation of our property and equipment using the
straight-line method over the estimated useful lives. Our method
of depreciation does not change when equipment becomes idle; we
continue to depreciate idled equipment on a straight-line basis.
No provision for salvage value is considered in determining
depreciation of our property and equipment. We review our
long-lived assets, including property and equipment, for
impairment whenever events or changes in circumstances indicate
that the carrying values of certain assets may not be recovered
over their estimated remaining useful lives. In connection with
this review, assets are grouped at the lowest level at which
identifiable cash flows are largely independent of other asset
groupings. The cyclical nature of our industry has resulted in
fluctuations in rig utilization over periods of time. Management
believes that the contract drilling industry will continue to be
cyclical and rig utilization will fluctuate. Based on
management’s expectations of future trends, we estimate
future cash flows over the life of the respective assets in our
assessment of impairment. These estimates of cash flows are
based on historical cyclical trends in the industry as well as
management’s expectations regarding the continuation of
these trends in the future. Provisions for asset impairment are
charged against income when estimated future cash flows, on an
undiscounted basis, are less than the asset’s net book
value. Any provision for impairment is measured based on
discounted cash flows.
On a periodic basis, we evaluate our fleet of drilling rigs for
marketability. During 2009 and 2008, in connection with our long
term planning process, we evaluated our then-current fleet of
marketable drilling rigs and identified 23 and 22 rigs,
respectively, that we determined would no longer be marketed as
rigs. Additionally, in 2009, we identified one rig which would
be recommissioned in a different configuration. The components
comprising these rigs were evaluated, and those components with
continuing utility to our other marketed rigs
19
Table of Contents
were transferred to other rigs or to our yards to be used as
spare equipment. The remaining components of these rigs were
impaired and the associated net book value of $10.5 million
in 2009 and $10.4 million in 2008 was expensed in our
consolidated statements of operations as an impairment charge.
In late 2008, we experienced a significant decrease in the
number of our rigs operating and oil and natural gas prices
decreased significantly. These events were deemed by us to be
triggering events that required us to perform an assessment with
respect to impairment of long-lived assets, including property
and equipment, in our contract drilling segment. With respect to
these long-lived assets, we estimated future cash flows over the
expected life of the long-lived assets, which were comprised
primarily of property and equipment, and determined that, on an
undiscounted basis, expected cash flows exceeded the carrying
value of the long-lived assets. Based on this assessment, no
impairment was indicated. We again performed an assessment with
respect to impairment of long-lived assets in our contract
drilling segment in 2009 based on undiscounted cash flows and
determined that no impairment was indicated. Impairment
considerations in our oil and natural gas segment related to
proved properties are discussed below. We concluded that no
triggering event had occurred with respect to our pressure
pumping segment, as the level of activity and revenue impact in
that segment had not been affected to the same degree as in our
other segments.
Oil and natural gas properties
— Working
interests in oil and natural gas properties are accounted for
using the successful efforts method of accounting. Under the
successful efforts method of accounting, exploration costs which
result in the discovery of oil and natural gas reserves and all
development costs are capitalized to the appropriate well.
Exploration costs which do not result in discovering oil and
natural gas reserves are charged to expense when such
determination is made. Costs of exploratory wells are initially
capitalized to wells in progress until the outcome of the
drilling is known. We review wells in progress quarterly to
determine whether sufficient progress is being made in assessing
the reserves and the economic operating viability of the
respective projects. If no progress has been made in assessing
the reserves and the economic operating viability of a project
after one year following the completion of drilling, we consider
the costs of the well to be impaired and recognize the costs as
expense. Geological and geophysical costs, including seismic
costs and costs to carry and retain undeveloped properties, are
charged to expense when incurred. The capitalized costs of both
developmental and successful exploratory type wells, consisting
of lease and well equipment, lease acquisition costs and
intangible development costs, are depreciated, depleted and
amortized on the
units-of-production
method, based on engineering estimates of proved oil and natural
gas reserves of each respective field.
We review our proved oil and natural gas properties for
impairment when a triggering event occurs such as downward
revisions in reserve estimates or decreases in oil and natural
gas prices. Proved properties are grouped by field and
undiscounted cash flow estimates are prepared based on our
expectation of future commodity prices over the lives of the
respective fields. These estimates are then reviewed by an
independent petroleum engineer. If the net book value of a field
exceeds its undiscounted cash flow estimate, impairment expense
is measured and recognized as the difference between its net
book value and discounted cash flow. The discounted cash flow
estimates used in measuring impairment are based on our
expectations of future commodity prices over the life of the
respective field. Unproved oil and natural gas properties are
reviewed quarterly to assess potential impairment. The intent to
drill, lease expiration and abandonment of area are considered.
Assessment of impairment is made on a
lease-by-lease
basis. If an unproved property is determined to be impaired,
then costs related to that property are expensed. Impairment
expense results from downward revisions in reserve estimates of
proved properties and amounted to approximately
$3.7 million, $4.4 million and $3.9 million for
the years ended December 31, 2009, 2008 and 2007,
respectively, is included in depreciation, depletion and
impairment in the accompanying consolidated statements of
operations.
Goodwill
— Goodwill is considered to have an
indefinite useful economic life and is not amortized. As such,
we assess impairment of our goodwill annually as of December 31
or on an interim basis if events or circumstances indicate that
the fair value of the asset has decreased below its carrying
value. Goodwill impairment testing is performed at the level of
our reporting units. Our reporting units have been determined to
be the same as our operating segments.
In connection with our annual assessment of potential impairment
of goodwill, we compare the fair value of the reporting unit
with its carrying value. If the fair value exceeds the carrying
value, no impairment is indicated. If the carrying value exceeds
the fair value, we measure any impairment of goodwill in that
reporting unit by allocating the fair value to the identifiable
assets and liabilities of the reporting unit based on their
respective fair
20
Table of Contents
values. Any excess unallocated fair value would equal the
implied fair value of goodwill, and if that amount is below the
carrying value of goodwill, an impairment charge is recognized.
In connection with our annual goodwill impairment assessment
performed as of December 31, 2008, we performed an
impairment test of goodwill recorded in our contract drilling
and drilling and completion fluids reporting units. In light of
the adverse market conditions affecting our common stock price
beginning in the fourth quarter of 2008 and continuing into
2009, including a significant decrease in the number of our rigs
operating and a significant decline in oil and natural gas
commodity prices, we utilized a discounted cash flow methodology
to estimate the fair values of our reporting units. In
completing the first step of our analysis, we used a three-year
projection of discounted cash flows, plus a terminal value
determined using the constant growth method to estimate the fair
value of our reporting units. In developing these fair value
estimates, we applied key assumptions, including an assumed
discount rate of 13.99% for all reporting units, an assumed
long-term growth rate of 3.50% for the contract drilling
reporting unit and an assumed long-term growth rate of 2.00% for
the drilling and completion fluids reporting unit.
Based on the results of the first step of the impairment test in
2008, we concluded that no impairment was indicated in the
contract drilling reporting unit as the estimated fair value of
that reporting unit exceeded its carrying value. An impairment
was indicated in our drilling and completion fluids reporting
unit as the estimated fair value of that reporting unit was less
than its carrying value. In validating this conclusion, we
considered the results of our long-lived asset impairment tests
and performed sensitivity analyses of the key assumptions used
in deriving the respective fair values of our reporting units.
We then performed the second step of the analysis of our
drilling and completion fluids reporting unit, which included
allocating the estimated fair value to the identifiable tangible
and intangible assets and liabilities of this reporting unit
based on their respective values. This allocation indicated no
residual value for goodwill, and accordingly we recorded an
impairment charge of $9.964 million in our
December 31, 2008 statement of operations. We exited
the drilling and completion fluids business on January 20,
2010, and the 2008 impairment charge is included in our loss
from discontinued operations in our statement of operations for
the year ended December 31, 2008.
We again performed our annual goodwill impairment assessment as
of December 31, 2009 related to the remaining
$86.2 million in goodwill recorded in our contract drilling
reporting unit. In completing the first step of our analysis, we
used a three-year projection of discounted cash flows, plus a
terminal value determined using the constant growth method to
estimate the fair value of our reporting unit. In developing
this fair value estimate, we applied key assumptions, including
an assumed discount rate of 15.42% and an assumed long-term
growth rate of 3.50%. Based on the results of the first step of
the impairment test in 2009, we concluded that no impairment was
indicated in our contract drilling reporting unit as the
estimated fair value of that reporting unit exceeded its
carrying value.
In the event that market conditions weaken, we may be required
to record an impairment of goodwill in our contract drilling
reporting unit in the future, and such impairment could be
material.
Revenue recognition
— Revenues are recognized
when services are performed, except for revenues earned under
turnkey contract drilling arrangements which are recognized
using the completed contract method of accounting. We follow the
percentage-of-completion
method of accounting for footage contract drilling arrangements.
Under the
percentage-of-completion
method, management estimates are relied upon in the
determination of the total estimated expenses to be incurred
drilling the well. Due to the nature of turnkey contract
drilling arrangements and risks therein, we follow the completed
contract method of accounting for such arrangements. Under this
method, revenues and expenses related to a well in progress are
deferred and recognized in the period the well is completed.
Provisions for losses on incomplete or in-process wells are made
when estimated total expenses are expected to exceed total
revenues. We recognize reimbursements received from third
parties for
out-of-pocket
expenses incurred as revenues and account for these
out-of-pocket
expenses as direct costs. Except for two wells drilled under
footage contacts in 2009, all of the wells we drilled in 2009,
2008 and 2007 were drilled under daywork contracts.
Use of estimates
— The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make certain estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent
assets and liabilities at the date of
21
Table of Contents
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from such estimates.
Key estimates used by management include:
| • | allowance for doubtful accounts, | |
| • | depreciation and depletion, | |
| • | goodwill and long-lived asset impairments, and | |
| • | reserves for self-insured levels of insurance coverage. |
For additional information on our accounting policies, see
Note 1 of Notes to Consolidated Financial Statements
included as a part of Item 8 of this Report.
Liquidity
and Capital Resources
As of December 31, 2009, we had working capital of
$264 million, including cash and cash equivalents of
$49.9 million. During 2009, our sources of cash flow
included:
| • | $454 million from operating activities, | |
| • | $3.4 million in proceeds from the disposal of property and equipment, and |
During 2009, we used $30.7 million to pay dividends on our
common stock, $6.2 million to pay issuance costs related to
our revolving credit facility, $1.6 million to repurchase
shares of our common stock and $453 million:
| • | to build new drilling rigs, | |
| • | to make capital expenditures for the betterment and refurbishment of our drilling rigs, | |
| • | to acquire and procure drilling equipment and facilities to support our drilling operations, | |
| • | to fund capital expenditures for our pressure pumping segment, and | |
| • | to fund investments in oil and natural gas properties on a working interest basis. |
We paid cash dividends during the year ended December 31,
2009 as follows:
| Per Share | Total | |||||||
| (In thousands) | ||||||||
|
Paid on March 31, 2009
|
$ | 0.05 | $ | 7,655 | ||||
|
Paid on June 30, 2009
|
0.05 | 7,675 | ||||||
|
Paid on September 30, 2009
|
0.05 | 7,675 | ||||||
|
Paid on December 30, 2009
|
0.05 | 7,676 | ||||||
|
Total cash dividends
|
$ | 0.20 | $ | 30,681 | ||||
On February 10, 2010, our Board of Directors approved a
cash dividend on our common stock in the amount of $0.05 per
share to be paid on March 30, 2010 to holders of record as
of March 15, 2010. The amount and timing of all future
dividend payments, if any, is subject to the discretion of the
Board of Directors and will depend upon business conditions,
results of operations, financial condition, terms of our credit
facilities and other factors.
On August 1, 2007, our Board of Directors approved a stock
buyback program (“Program”), authorizing purchases of
up to $250 million of our common stock in open market or
privately negotiated transactions. During the year ended
December 31, 2009, we purchased 5,715 shares of our
common stock under the Program at a cost of approximately
$79,000. As of December 31, 2009, we are authorized to
purchase approximately $113 million of our outstanding
common stock under the Program.
We have an unsecured revolving credit facility with a maximum
borrowing and letter of credit capacity of $240 million.
Interest is paid on the outstanding principal amount of
borrowings under the revolving credit facility at a floating
rate based on, at our election, LIBOR or a base rate. The margin
on LIBOR loans ranges from 3.00% to
22
Table of Contents
4.00% and the margin on base rate loans ranges from 2.00% to
3.00%, based on our debt to capitalization ratio. Any
outstanding borrowings must be repaid at maturity on
January 31, 2012 and letters of credit may remain in effect
up to six months after such maturity date. As of
December 31, 2009, we had no borrowings outstanding under
the revolving credit facility. We had $46.3 million in
letters of credit outstanding at December 31, 2009, and as
a result, had available borrowing capacity of approximately
$194 million at such date.
There are customary representations, warranties, restrictions
and covenants associated with the revolving credit facility.
Financial covenants provide for a maximum debt to capitalization
ratio and a minimum interest coverage ratio. As of
December 31, 2009, the maximum debt to capitalization ratio
was 35% and the minimum interest coverage ratio was 3.00 to 1.
We were in compliance with these financial covenants as of
December 31, 2009. We do not expect that the restrictions
and covenants will impact our ability to operate or react to
opportunities that might arise.
We believe that the current level of cash, short-term
investments and borrowing capacity available under our revolving
credit facility, together with cash expected to be generated
from operations (including expected income tax refunds in 2010
of approximately $114 million resulting from the carry-back
of net operating losses), should be sufficient to meet our
current capital needs. From time to time, opportunities to
expand our business, including acquisitions and the building of
new rigs are evaluated. The timing, size or success of any
acquisition and the associated capital commitments are
unpredictable. If we pursue opportunities for growth that
require capital, we believe we would be able to satisfy these
needs through a combination of working capital, cash generated
from operations, borrowing capacity under our revolving credit
facility or additional debt or equity financing. However, there
can be no assurance that such capital will be available on
reasonable terms, if at all.
Contractual
Obligations
The following table presents information with respect to our
contractual obligations as of December 31, 2009 (dollars in
thousands):
| Payments due by period | ||||||||||||||||||||
|
Less Than 1
|
More Than 5
|
|||||||||||||||||||
| Total | Year | 1-3 Years | 3-5 Years | Years | ||||||||||||||||
|
Borrowings under revolving credit facility(1)
|
$ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
|
Commitments to purchase equipment(2)
|
186,220 | 186,220 | — | — | — | |||||||||||||||
| $ | 186,220 | $ | 186,220 | $ | — | $ | — | $ | — | |||||||||||
| (1) | No borrowings were outstanding on our revolving credit facility as of December 31, 2009. Our revolving credit facility matures on January 31, 2012. | |
| (2) | Represents commitments to purchase major equipment to be delivered in 2010 based on expected delivery dates. |
Off-Balance
Sheet Arrangements
We had no off-balance sheet arrangements at December 31,
2009.
23
Table of Contents
Results
of Operations
Comparison
of the years ended December 31, 2009 and 2008
The following tables summarize operations by business segment
for the years ended December 31, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
|
Contract Drilling
|
2009 | 2008 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues
|
$ | 599,287 | $ | 1,804,026 | (66.8 | )% | ||||||
|
Direct operating costs
|
$ | 357,742 | $ | 1,038,327 | (65.5 | )% | ||||||
|
Selling, general and administrative
|
$ | 4,340 | $ | 5,363 | (19.1 | )% | ||||||
|
Depreciation and impairment
|
$ | 248,424 | $ | 239,700 | 3.6 | % | ||||||
|
Operating income (loss)
|
$ | (11,219 | ) | $ | 520,636 | N/A | % | |||||
|
Operating days
|
33,394 | 93,068 | (64.1 | )% | ||||||||
|
Average revenue per operating day
|
$ | 17.95 | $ | 19.38 | (7.4 | )% | ||||||
|
Average direct operating costs per operating day
|
$ | 10.71 | $ | 11.16 | (4.0 | )% | ||||||
|
Average rigs operating
|
91 | 254 | (64.2 | )% | ||||||||
|
Capital expenditures
|
$ | 395,376 | $ | 360,645 | 9.6 | % | ||||||
The demand for our contract drilling services is impacted by the
market price of natural gas and, to a lesser extent, oil. The
reactivation and construction of new land drilling rigs in the
United States in recent years has also contributed to an excess
capacity of land drilling rigs compared to demand. The average
market price of natural gas for each of the fiscal quarters and
full years in 2009 and 2008 follow:
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Year | ||||||||||||||||
|
2008:
|
||||||||||||||||||||
|
Average natural gas price(1)
|
$ | 8.92 | $ | 11.74 | $ | 9.28 | $ | 6.60 | $ | 9.13 | ||||||||||
|
2009:
|
||||||||||||||||||||
|
Average natural gas price(1)
|
$ | 4.71 | $ | 3.82 | $ | 3.26 | $ | 4.46 | $ | 4.06 | ||||||||||
| (1) | The average natural gas price represents the Henry Hub Spot price as reported by the United States Energy Information Administration. |
Revenues and direct operating costs decreased in 2009 compared
to 2008 primarily as a result of a decrease in the number of
operating days. The decrease in operating days was due to
decreased demand largely caused by lower commodity prices for
natural gas and oil. Our average number of rigs operating during
2009 included an average of approximately six rigs under term
contracts that earned standby revenues of $22.3 million.
This represented an increase from an average of approximately
one rig under term contract that earned standby revenues of
$4.7 million in 2008. Rigs on standby earn a discounted
dayrate as they do not have crews and have lower costs. We
recognized approximately $8.0 million of revenues during
2009 from the early termination of drilling contracts compared
to approximately $1.3 million in 2008. Average revenue per
operating day decreased in 2009 primarily due to decreases in
dayrates for rigs that were operating in the spot market and the
expiration of term contracts that were entered into at higher
rates. Average direct operating costs per operating day
decreased in 2009 primarily due to decreases in labor and repair
costs. Significant capital expenditures were incurred in 2009
and 2008 to build new drilling rigs, to modify and upgrade our
drilling rigs and to acquire additional related equipment such
as drill pipe, drill collars, engines, fluid circulating
systems, rig hoisting systems and safety enhancement equipment.
Depreciation and impairment expense includes approximately
$10.5 million in 2009 and approximately $10.4 million
in 2008 related to the impairment of drilling equipment
primarily related to drilling rigs that were removed from our
24
Table of Contents
marketable fleet. We removed 23 rigs from our marketable fleet
in 2009 and removed 22 rigs from our marketable fleet in 2008.
Depreciation expense increased as a result of capital
expenditures.
| Year Ended December 31, | ||||||||||||
|
Pressure Pumping
|
2009 | 2008 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues
|
$ | 161,441 | $ | 217,494 | (25.8 | )% | ||||||
|
Direct operating costs
|
$ | 111,414 | $ | 132,570 | (16.0 | )% | ||||||
|
Selling, general and administrative
|
$ | 21,421 | $ | 23,305 | (8.1 | )% | ||||||
|
Depreciation
|
$ | 27,589 | $ | 19,600 | 40.8 | % | ||||||
|
Operating income
|
$ | 1,017 | $ | 42,019 | (97.6 | )% | ||||||
|
Total jobs
|
7,265 | 12,900 | (43.7 | )% | ||||||||
|
Average revenue per job
|
$ | 22.22 | $ | 16.86 | 31.8 | % | ||||||
|
Average direct operating costs per job
|
$ | 15.34 | $ | 10.28 | 49.2 | % | ||||||
|
Capital expenditures
|
$ | 43,144 | $ | 61,289 | (29.6 | )% | ||||||
Our customers have increased their focus on the emerging
development of unconventional reservoirs in the Appalachian
Basin and the larger jobs associated therewith. As a result of
this focus on unconventional reservoirs and lower commodity
prices, we experienced a decrease in smaller traditional
pressure pumping jobs, which contributed to the overall decrease
in the number of total jobs. Revenues and direct operating costs
decreased as a result of the decrease in the number of total
jobs. Increased average revenue per job reflects an increase in
the proportion of larger jobs to total jobs, which was driven by
demand for services associated with unconventional reservoirs,
partially offset by the impact of reduced pricing. Average
direct operating costs per job increased due to the increase in
larger jobs and as a result of fixed costs being spread over a
significantly reduced number of total jobs. In anticipation of
increased activity associated with the unconventional reservoirs
in the Appalachian Basin, we have added facilities, equipment
and personnel in recent years. Delays in the development of
these reservoirs and lower commodity prices have caused a slower
increase in customer activity than we had expected, negatively
impacting the profitability of this business. Selling, general
and administrative expenses decreased primarily as a result of
cost containment efforts during the downturn in the industry.
Significant capital expenditures have been incurred in recent
years to add capacity. Depreciation expense increased as a
result of capital expenditures.
| Year Ended December 31, | ||||||||||||
|
Oil and Natural Gas Production and Exploration
|
2009 | 2008 | % Change | |||||||||
| (Dollars in thousands, except commodity prices) | ||||||||||||
|
Revenues
|
$ | 21,218 | $ | 42,360 | (49.9 | )% | ||||||
|
Direct operating costs
|
$ | 7,341 | $ | 12,793 | (42.6 | )% | ||||||
|
Depreciation, depletion and impairment
|
$ | 12,927 | $ | 15,856 | (18.5 | )% | ||||||
|
Operating income
|
$ | 950 | $ | 13,711 | (93.1 | )% | ||||||
|
Capital expenditures
|
$ | 7,341 | $ | 22,981 | (68.1 | )% | ||||||
|
Average net daily oil production (Bbls)
|
761 | 801 | (5.0 | )% | ||||||||
|
Average net daily gas production (Mcf)
|
3,225 | 3,755 | (14.1 | )% | ||||||||
|
Average oil sales price (per Bbl)
|
$ | 58.09 | $ | 98.70 | (41.1 | )% | ||||||
|
Average gas sales price (per Mcf)
|
$ | 4.32 | $ | 9.77 | (55.8 | )% | ||||||
Revenues decreased due to lower average sales prices and lower
average net daily production of oil and natural gas. Average net
daily oil and natural gas production decreased primarily due to
production declines on existing wells. Direct operating costs
decreased primarily due to decreases in seismic expenses as well
as decreased production taxes and other production costs.
Depreciation, depletion and impairment expense in 2009 includes
approximately $3.7 million incurred to impair certain oil
and natural gas properties compared to approximately
$4.4 million incurred to impair certain oil and natural gas
properties in 2008. Depletion expense decreased approximately
$2.3 million primarily due to lower production and the
impact of decreases in the carrying value of
25
Table of Contents
properties resulting from previous impairment charges. Capital
expenditures decreased in 2009 as a result of declines in
commodity prices.
| Year Ended December 31, | ||||||||||||
|
Corporate and Other
|
2009 | 2008 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Selling, general and administrative
|
$ | 30,860 | $ | 29,412 | 4.9 | % | ||||||
|
Depreciation
|
$ | 907 | $ | 834 | 8.8 | % | ||||||
|
Other operating expenses
|
$ | 3,810 | $ | 4,350 | (12.4 | )% | ||||||
|
Net (gain) loss on asset disposals
|
$ | 3,385 | $ | (4,163 | ) | N/A | % | |||||
|
Interest income
|
$ | 381 | $ | 1,553 | (75.5 | )% | ||||||
|
Interest expense
|
$ | 4,148 | $ | 630 | 558.4 | % | ||||||
|
Other income
|
$ | 426 | $ | 502 | (15.1 | )% | ||||||
|
Capital expenditures
|
$ | 6,785 | $ | 511 | 1,227.8 | % | ||||||
Selling, general and administrative expense increased in 2009
primarily as a result of increased professional fees. Other
operating expenses decreased due to a decrease in bad debt
expense. Gains and losses on the disposal of assets are treated
as part of our corporate activities because such transactions
relate to corporate strategy decisions of our executive
management group. Losses on asset disposals in 2009 were
primarily related to the disposal of contract drilling
equipment. Gains on asset disposals in 2008 were primarily
related to gains on the sale of contract drilling equipment and
the sale of oil and natural gas properties. Interest expense
increased in 2009 due to the amortization of revolving credit
facility issuance costs and increased fees associated with
outstanding letters of credit and the unused portion of the
revolving credit facility. Capital expenditures increased in
2009 due to the purchase and ongoing implementation of a new
enterprise resource planning system.
| Year Ended December 31, | ||||||||||||
|
Discontinued Operations:
|
2009 | 2008 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Drilling and completion fluids revenue
|
$ | 79,786 | $ | 145,246 | (45.1 | )% | ||||||
|
Drilling and completion fluids direct operating costs
|
$ | 74,180 | $ | 126,900 | (41.5 | )% | ||||||
|
Drilling and completion fluids selling, general and
administrative
|
$ | 7,192 | $ | 10,110 | (28.9 | )% | ||||||
|
Drilling and completion fluids depreciation
|
$ | 2,287 | $ | 2,830 | (29.2 | )% | ||||||
|
Goodwill impairment
|
$ | — | $ | 9,964 | (100.0 | )% | ||||||
|
Impairment of assets held for sale
|
$ | 1,900 | $ | — | N/A | % | ||||||
|
Net gain on asset disposals/retirements
|
$ | (125 | ) | $ | (155 | ) | (19.4 | )% | ||||
|
Other operating expense
|
$ | 890 | $ | — | N/A | % | ||||||
|
Net interest expense
|
$ | — | $ | 7 | (100.0 | )% | ||||||
|
Income tax expense (benefit)
|
$ | (2,208 | ) | $ | 2,389 | N/A | % | |||||
|
Loss from discontinued operations, net of income taxes
|
$ | (4,330 | ) | $ | (6,799 | ) | 36.3 | % | ||||
On January 20, 2010, we exited our drilling and completion
fluids services business which had previously been presented as
one of our reportable operating segments. On that date, our
wholly owned subsidiary, Ambar Lone Star Fluids Services LLC,
completed the sale of substantially all of its assets, excluding
billed accounts receivable. Upon our exit from this business, we
classified our drilling and completion fluids operating segment
as a discontinued operation. Accordingly, the assets and
liabilities of this business, along with its results of
operations, have been reclassified for all periods presented.
Drilling and completion fluids revenue and direct operating
costs decreased in 2009 due to decreased sales volume both on
land and offshore in the Gulf of Mexico. Drilling and completion
fluids selling, general and administrative expenses decreased in
2009 primarily due to a decrease in compensation costs for sales
and support personnel due to headcount reductions. Goodwill
impairment was recognized in the drilling and completion fluids
reporting unit in 2008 as a result of our annual impairment
testing which indicated that the fair value of goodwill in that
reporting unit was zero. Impairment of assets held for sale in
2009 of $1.9 million represents the adjustment recorded to
reduce the carrying value of the assets sold to their fair value
less transaction
26
Table of Contents
costs as of December 31, 2009. In 2008, income tax expense
was recognized despite a pre-tax loss in the drilling and
completion fluids business due to the fact that the goodwill
impairment recorded in that year was not deductible for tax
purposes.
Comparison
of the years ended December 31, 2008 and 2007
The following tables summarize operations by business segment
for the years ended December 31, 2008 and 2007:
| Year Ended December 31, | ||||||||||||
|
Contract Drilling
|
2008 | 2007 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues
|
$ | 1,804,026 | $ | 1,741,647 | 3.6 | % | ||||||
|
Direct operating costs
|
$ | 1,038,327 | $ | 963,150 | 7.8 | % | ||||||
|
Selling, general and administrative
|
$ | 5,363 | $ | 5,893 | (9.0 | )% | ||||||
|
Depreciation and impairment
|
$ | 239,700 | $ | 213,812 | 12.1 | % | ||||||
|
Operating income
|
$ | 520,636 | $ | 558,792 | (6.8 | )% | ||||||
|
Operating days
|
93,068 | 89,095 | 4.5 | % | ||||||||
|
Average revenue per operating day
|
$ | 19.38 | $ | 19.55 | (0.9 | )% | ||||||
|
Average direct operating costs per operating day
|
$ | 11.16 | $ | 10.81 | 3.2 | % | ||||||
|
Average rigs operating
|
254 | 244 | 4.1 | % | ||||||||
|
Capital expenditures
|
$ | 360,645 | $ | 539,506 | (33.2 | )% | ||||||
The demand for our contract drilling services is impacted by the
market price of natural gas and, to a lesser extent, oil. The
reactivation and construction of new land drilling rigs in the
United States in recent years has also contributed to an excess
capacity of land drilling rigs compared to demand. The average
market price of natural gas for each of the fiscal quarters and
full years in 2008 and 2007 follow:
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Year | ||||||||||||||||
|
2007:
|
||||||||||||||||||||
|
Average natural gas price(1)
|
$ | 7.44 | $ | 7.76 | $ | 6.35 | $ | 7.19 | $ | 7.18 | ||||||||||
|
2008:
|
||||||||||||||||||||
|
Average natural gas price(1)
|
$ | 8.92 | $ | 11.74 | $ | 9.28 | $ | 6.60 | $ | 9.13 | ||||||||||
| (1) | The average natural gas price represents the Henry Hub Spot price as reported by the United States Energy Information Administration. |
Revenues and direct operating costs increased in 2008 compared
to 2007 primarily as a result of an increase in the number of
operating days. The increase in operating days was due to
increased demand caused by higher prices for natural gas during
most of 2008 compared to 2007. Average revenue per operating day
in 2008 was relatively flat compared to 2007. Average direct
operating costs per operating day increased in 2008 due to
incremental costs incurred to activate idle drilling rigs as
well as increases in labor, repairs and other related costs.
Significant capital expenditures were incurred in 2008 and 2007
to build new drilling rigs, to modify and upgrade our drilling
rigs and to acquire additional related equipment such as drill
pipe, drill collars, engines, fluid circulating systems, rig
hoisting systems and safety enhancement equipment. Depreciation
and impairment expense in 2008 includes approximately
$10.4 million related to the impairment of drilling
equipment primarily related to drilling rigs
27
Table of Contents
thatwere removed from our marketable fleet. We removed 22 rigs
from our marketable fleet in 2008. Depreciation expense
increased as a result of capital expenditures.
| Year Ended December 31, | ||||||||||||
|
Pressure Pumping
|
2008 | 2007 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues
|
$ | 217,494 | $ | 202,812 | 7.2 | % | ||||||
|
Direct operating costs
|
$ | 132,570 | $ | 105,273 | 25.9 | % | ||||||
|
Selling, general and administrative
|
$ | 23,305 | $ | 18,971 | 22.8 | % | ||||||
|
Depreciation
|
$ | 19,600 | $ | 14,311 | 37.0 | % | ||||||
|
Operating income
|
$ | 42,019 | $ | 64,257 | (34.6 | )% | ||||||
|
Total jobs
|
12,900 | 14,094 | (8.5 | )% | ||||||||
|
Average revenue per job
|
$ | 16.86 | $ | 14.39 | 17.2 | % | ||||||
|
Average direct operating costs per job
|
$ | 10.28 | $ | 7.47 | 37.6 | % | ||||||
|
Capital expenditures
|
$ | 61,289 | $ | 47,582 | 28.8 | % | ||||||
Our customers increased their focus on the emerging development
of unconventional reservoirs in the Appalachian Basin and the
larger jobs associated therewith. As a result of this focus on
unconventional reservoirs, we experienced a decrease in smaller
traditional pressure pumping jobs in 2008, which resulted in an
overall decrease in the number of total jobs. Revenues and
direct operating costs increased as a result of an increase in
the average revenue and average direct operating costs per job.
Increased average revenue per job was due to an increase in the
proportion of larger jobs to total jobs, which was driven by
demand for services associated with unconventional reservoirs.
Average direct operating costs per job increased due to the
increase in larger jobs and as a result of increases in
compensation, maintenance and the cost of materials used in our
operations. In anticipation of increased activity associated
with the unconventional reservoirs in the Appalachian Basin, we
added facilities, equipment and personnel. Delays in the
development of these reservoirs caused a slower increase in
customer activity than we had expected, negatively impacting the
profitability of this business. Selling, general and
administrative expense increased primarily as a result of
expenses to support expanded operations of this segment.
Significant capital expenditures were incurred to add capacity,
expand our areas of operation and modify and upgrade existing
equipment. Depreciation expense increased as a result of capital
expenditures.
| Year Ended December 31, | ||||||||||||
|
Oil and Natural Gas Production and Exploration
|
2008 | 2007 | % Change | |||||||||
| (Dollars in thousands, except commodity prices) | ||||||||||||
|
Revenues
|
$ | 42,360 | $ | 41,637 | 1.7 | % | ||||||
|
Direct operating costs
|
$ | 12,793 | $ | 10,864 | 17.8 | % | ||||||
|
Selling, general and administrative
|
$ | — | $ | 2,365 | (100.0 | )% | ||||||
|
Depreciation, depletion and impairment
|
$ | 15,856 | $ | 17,410 | (8.9 | )% | ||||||
|
Operating income
|
$ | 13,711 | $ | 10,998 | 24.7 | % | ||||||
|
Capital expenditures
|
$ | 22,981 | $ | 17,516 | 31.2 | % | ||||||
|
Average net daily oil production (Bbls)
|
801 | 971 | (17.5 | )% | ||||||||
|
Average net daily gas production (Mcf)
|
3,755 | 4,996 | (24.8 | )% | ||||||||
|
Average oil sales price (per Bbl)
|
$ | 98.70 | $ | 68.82 | 43.4 | % | ||||||
|
Average gas sales price (per Mcf)
|
$ | 9.77 | $ | 7.37 | 32.6 | % | ||||||
Revenues increased due to higher average sales prices of oil and
natural gas. This increase was partially offset by a decrease in
the average net daily production of oil and natural gas and by
the elimination of well operations revenue due to the fourth
quarter 2007 sale of the operating responsibilities associated
with oil and natural gas wells. Average net daily oil and
natural gas production decreased primarily due to the sale of
properties in 2007 and production declines. Direct operating
costs increased due to an increase in seismic expenses as well
as increased production taxes and other production costs.
Selling, general and administrative expense decreased in 2008
due to the sale of the operating responsibilities mentioned
above and the resulting elimination of headcount in this
28
Table of Contents
segment. Depreciation, depletion and impairment expense in 2008
includes approximately $4.4 million incurred to impair
certain oil and natural gas properties compared to approximately
$3.9 million incurred to impair certain oil and natural gas
properties in 2007. Depletion expense decreased approximately
$1.9 million primarily due to the sale of certain
properties in 2007.
| Year Ended December 31, | ||||||||||||
|
Corporate and Other
|
2008 | 2007 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Selling, general and administrative
|
$ | 29,412 | $ | 27,436 | 7.2 | % | ||||||
|
Depreciation
|
$ | 834 | $ | 813 | 2.6 | % | ||||||
|
Other operating expenses
|
$ | 4,350 | $ | 2,875 | 51.3 | % | ||||||
|
Embezzlement recoveries
|
$ | — | $ | (43,955 | ) | (100.0 | )% | |||||
|
Net gain on asset disposals
|
$ | (4,163 | ) | $ | (16,432 | ) | (74.7 | )% | ||||
|
Interest income
|
$ | 1,553 | $ | 2,351 | (33.9 | )% | ||||||
|
Interest expense
|
$ | 630 | $ | 2,187 | (71.2 | )% | ||||||
|
Other income
|
$ | 502 | $ | 363 | 38.3 | % | ||||||
|
Capital expenditures
|
$ | 511 | $ | — | N/A | % | ||||||
Selling, general and administrative expense increased primarily
as a result of additional compensation expense and an increase
in payroll tax expense associated with the exercise of stock
options during 2008. Other operating expenses increased due to
an increase in bad debt expense. Gains and losses on the
disposal of assets are considered as part of our corporate
activities because such transactions relate to corporate
strategy decisions of our executive management group. Gains on
asset disposals in 2008 were primarily related to gains on the
sale of contract drilling equipment and the sale of oil and
natural gas properties. Gains on asset disposals in 2007 were
primarily related to the sale of oil and natural gas properties.
In November 2005, we discovered that our former Chief Financial
Officer, Jonathan D. Nelson (“Nelson”), had
fraudulently diverted approximately $77.5 million in
Company funds for his own benefit during the period from 1998
through 2005. As a result, the Audit Committee of the Board of
Directors commenced an investigation into Nelson’s
activities and retained independent counsel and independent
forensic accountants to assist with the investigation. Nelson
has been sentenced and is serving a term of imprisonment arising
out of his embezzlement. A receiver was appointed to take
control of and liquidate the assets of Nelson. In May 2007, the
court approved a plan of distribution for the assets recovered
by the receiver. We recovered a total of approximately
$44.5 million pursuant to the approved plan, and we
recognized this recovery in our consolidated statement of income
in 2007, net of professional fees incurred as a result of the
embezzlement.
| Year Ended December 31, | ||||||||||||
|
Discontinued Operations:
|
2008 | 2007 | % Change | |||||||||
| (Dollars in thousands) | ||||||||||||
|
Drilling and completion fluids revenue
|
$ | 145,246 | $ | 128,098 | 13.4 | % | ||||||
|
Drilling and completion fluids direct operating costs
|
$ | 126,900 | $ | 108,752 | 16.7 | % | ||||||
|
Drilling and completion fluids selling, general and
administrative
|
$ | 10,110 | $ | 9,958 | 1.5 | % | ||||||
|
Drilling and completion fluids depreciation
|
$ | 2,830 | $ | 2,860 | (1.0 | )% | ||||||
|
Goodwill impairment
|
$ | 9,964 | $ | — | N/A | % | ||||||
|
Net gain on asset disposals/retirements
|
$ | (155 | ) | $ | (113 | ) | 37.2 | % | ||||
|
Other operating benefit
|
$ | — | $ | (325 | ) | (100.0 | )% | |||||
|
Net interest expense (income)
|
$ | 7 | $ | (4 | ) | N/A | % | |||||
|
Income tax expense
|
$ | 2,389 | $ | 2,818 | (15.2 | )% | ||||||
|
Income (loss) from discontinued operations, net of income taxes
|
$ | (6,799 | ) | $ | 4,152 | N/A | % | |||||
29
Table of Contents
Drilling and completion fluids revenue and direct operating
costs increased in 2008 due to increased sales volume both on
land and offshore in the Gulf of Mexico. Goodwill impairment was
recognized in the drilling and completion fluids reporting unit
in 2008 as a result of our annual impairment testing which
indicated that the fair value of goodwill in that reporting unit
was zero. No impairment of goodwill was recognized in 2007 as
the annual impairment testing did not indicate that an
impairment existed at that time. In 2008, income tax expense was
recognized despite a pre-tax loss in the drilling and completion
fluids business due to the fact that the goodwill impairment
recorded in that year was not deductible for tax purposes.
Income
Taxes
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Income (loss) from continuing operations before income tax
|
$ | (51,555 | ) | $ | 547,358 | $ | 663,837 | |||||
|
Income tax expense (benefit)
|
(17,595 | ) | 193,490 | 229,350 | ||||||||
|
Effective tax rate
|
34.1 | % | 35.3 | % | 34.5 | % | ||||||
The effective tax rate is a result of a Federal rate of 35.0%
adjusted as follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Statutory tax rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State income taxes
|
4.7 | 1.7 | 1.4 | |||||||||
|
Permanent differences
|
(5.7 | ) | (1.2 | ) | (1.6 | ) | ||||||
|
Other, net
|
0.1 | (0.2 | ) | (0.3 | ) | |||||||
|
Effective tax rate
|
34.1 | % | 35.3 | % | 34.5 | % | ||||||
The permanent differences indicated above are largely
attributable to our Domestic Production Activities deduction.
The Domestic Production Activities Deduction was enacted as part
of the American Jobs Creation Act of 2004 (as revised by the
Emergency Economic Stabilization Act of 2008, the
“Act”) and is effective for taxable years after
December 31, 2004. The Act allows a deduction of 6% on the
lesser of qualified production activities income or taxable
income.
We record deferred Federal income taxes based primarily on the
temporary differences between the book and tax bases of our
assets. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the
year in which those temporary differences are expected to be
settled. As a result of fully recognizing the benefit of our
deferred income taxes, we incur deferred income tax expense as
these benefits are utilized. We recognized deferred tax expense
of approximately $101 million in 2009, $65.4 million
in 2008 and $38.3 million in 2007.
Volatility
of Oil and Natural Gas Prices and its Impact on Operations and
Financial Condition
Our revenue, profitability, financial condition and rate of
growth are substantially dependent upon prevailing prices for
natural gas and, to a lesser extent, oil. For many years, oil
and natural gas prices and markets have been extremely volatile.
Prices are affected by market supply and demand factors as well
as international military, political and economic conditions,
and the ability of OPEC to set and maintain production and price
targets. All of these factors are beyond our control. During
2008, the monthly average market price of natural gas (monthly
average Henry Hub price as reported by the Energy Information
Administration) peaked in June at $13.06 per Mcf before rapidly
declining to an average of $5.99 per Mcf in December. In 2009,
the monthly average market price of natural gas declined further
to a low of $3.06 per Mcf in September. This decline in the
market price of natural gas resulted in our customers
significantly reducing their drilling activities beginning in
the fourth quarter of 2008 and drilling activities remained low
throughout 2009. This reduction in demand combined with the
reactivation and construction of new land drilling rigs in the
United States during the last several years has resulted in
excess capacity compared to demand. As a result of these
factors, our average number of rigs operating has declined
significantly. We expect oil and natural gas prices to continue
to be volatile and to affect our financial condition,
30
Table of Contents
operations and ability to access sources of capital. Low market
prices for natural gas would likely result in demand for our
drilling rigs remaining low and adversely affect our operating
results, financial condition and cash flows.
The North American land drilling industry has experienced
downturns in demand during the last decade. During these
periods, there have been substantially more drilling rigs
available than necessary to meet demand. As a result, drilling
contractors have had difficulty sustaining profit margins and,
at times, have incurred losses during the downturn periods.
Impact of
Inflation
Inflation has not had a significant impact on our operations
during the three years in the period ended December 31,
2009. We believe that inflation will not have a significant
near-term impact on our financial position.
Recently
Issued Accounting Standards
In June 2008, the FASB issued a new accounting standard which
clarifies that share-based payment awards that entitle their
holders to receive non-forfeitable dividends before vesting
should be considered participating securities and, as such,
should be included in the calculation of basic
earnings-per-share
using the two-class method. Certain of our share-based payment
awards entitle the holders to receive non-forfeitable dividends.
This standard is effective for financial statements issued for
fiscal years beginning after December 15, 2008, as well as
interim periods within those years and became effective for us
on January 1, 2009. The impact of the adoption of this
standard is discussed in Note 1 of our Consolidated
Financial Statements.
In December 2008, the SEC issued a Final Rule,
Modernization
of Oil and Gas Reporting
(“Final Rule”). The Final
Rule revises certain 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. The amendments are designed to modernize and
update oil and gas disclosure requirements to align them with
current practices and changes in technology. 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. We applied
the provisions of the Final Rule in connection with our
December 31, 2009 oil and natural gas reserve estimation
process. The application of the Final Rule did not have a
material impact on us.
In April 2009, the FASB issued a staff position to provide
additional guidance for determining whether a market for a
financial asset is not active and a transaction is not
distressed for fair value measurements under generally accepted
accounting principles. The provisions of this staff position are
effective for financial statements issued for interim and annual
periods ending after June 15, 2009 and became effective for
us in the quarter ended June 30, 2009. The adoption of this
staff position did not have a material impact on us.
In April 2009, the FASB issued a staff position which increases
the frequency of fair value disclosures for financial
instruments from annual only to quarterly reporting periods. The
provisions of this staff position are effective for financial
statements issued for interim and annual periods ending after
June 15, 2009 and became effective for us in the quarter
ended June 30, 2009. The adoption of this staff position
did not have a material impact on us.
In June 2009, the FASB issued a new accounting standard that
amends the accounting and disclosure requirements for the
consolidation of variable interest entities. This new standard
removes the previously existing exception from applying
consolidation guidance to qualifying special-purpose entities
and requires ongoing reassessments of whether an enterprise is
the primary beneficiary of a variable interest entity. Before
this new standard, generally accepted accounting principles
required reconsideration of whether an enterprise is the primary
beneficiary of a variable interest entity only when specific
events occurred. This new standard is effective as of the
beginning of each reporting entity’s first annual reporting
period that begins after November 15, 2009, for interim
periods within that first annual reporting period, and for
interim and annual reporting periods thereafter. This new
standard became effective for us on January 1, 2010. The
adoption of this standard did not impact our consolidated
financial statements.
In June 2009, the FASB issued the FASB Accounting Standards
Codification (“Codification”). Effective for financial
statements issued for interim and annual periods ending after
September 15, 2009, the Codification
31
Table of Contents
became the source of authoritative U.S. generally accepted
accounting principles. The FASB will no longer issue new
standards in the form of Statements, FASB Staff Positions or
EITF Abstracts. Instead, it will issue Accounting Standards
Updates to update the Codification. The adoption of the
Codification did not impact our consolidated financial
statements.
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
We currently have exposure to interest rate market risk
associated with any borrowings that we have under our revolving
credit facility. The revolving credit facility calls for
periodic interest payments at a floating rate ranging from LIBOR
plus 3.00% to 4.00% or at the prime rate. The applicable rate
above LIBOR is based upon our debt to capitalization ratio. As
of December 31, 2009, we had no borrowings outstanding
under our revolving credit facility.
We conduct a portion of our business in Canadian dollars through
our Canadian land-based drilling operations. The exchange rate
between Canadian dollars and U.S. dollars has fluctuated
during the last several years. If the value of the Canadian
dollar against the U.S. dollar weakens, revenues and
earnings of our Canadian operations will be reduced and the
value of our Canadian net assets will decline when they are
translated to U.S. dollars.
The carrying values of cash and cash equivalents, trade
receivables and accounts payable approximate fair value due to
the short-term maturity of these items.
| Item 8. | Financial Statements and Supplementary Data. |
Financial Statements are filed as a part of this Report at the
end of Part IV hereof beginning at
page F-1,
Index to Consolidated Financial Statements, and are incorporated
herein by this reference.
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. |
None.
| Item 9A. | Controls and Procedures. |
Disclosure
Controls and Procedures:
Under the supervision and with the participation of our
management, including our Chief Executive Officer (CEO) and
Chief Financial Officer (CFO), we conducted an evaluation of the
effectiveness of our disclosure controls and procedures, as such
term is defined in
Rules 13a-15(e)
and
15d-15(e)
promulgated under the Exchange Act, as of the end of the period
covered by this Report. Based on this evaluation, our CEO and
CFO concluded that, as of December 31, 2009, our disclosure
controls and procedures were effective to ensure that
information required to be disclosed by us in reports that we
file or submit under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in SEC
rules and forms and is accumulated and reported to our
management, including our CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure.
Management’s
Report on Internal Control over Financial Reporting:
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as defined
in Exchange Act
Rule 13a-15(f).
Under the supervision and with the participation of our
management, including our CEO and CFO, we carried out an
evaluation of the effectiveness of our internal control over
financial reporting as of December 31, 2009, based on the
Internal Control-Integrated Framework
issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. Based on this evaluation, our management has
concluded that our internal control over financial reporting was
effective as of December 31, 2009.
The effectiveness of our internal control over financial
reporting as of December 31, 2009 has been audited by
PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which appears on
page F-2
of this Report and is incorporated by reference into Item 8
of this Report.
32
Table of Contents
Changes
in Internal Control over Financial Reporting:
There have been no changes in our internal control over
financial reporting during the most recently completed fiscal
quarter that have materially affected, or are reasonably likely
to materially affect, our internal control over financial
reporting.
| Item 9B. | Other Information |
None.
33
Table of Contents
The information required by Part III is omitted from this
Report because we expect to file a definitive proxy statement
(the “Proxy Statement”) pursuant to
Regulation 14A of the Securities Exchange Act of 1934 no
later than 120 days after the end of the fiscal year
covered by this Report and certain information included therein
is incorporated herein by reference.
| Item 10. | Directors, Executive Officers and Corporate Governance. |
The information required by this Item is incorporated herein by
reference to the Proxy Statement.
We have adopted a Code of Business Conduct and Ethics for Senior
Financial Executives, which covers, among others, our principal
executive officer, principal financial officer and principal
accounting officer. The text of this code is located on our
website under “Governance.” Our Internet address is
www.patenergy.com. We intend to disclose any amendments to or
waivers from this code on our website.
| Item 11. | Executive Compensation. |
The information required by this Item is incorporated herein by
reference to the Proxy Statement.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. |
The information required by this Item is incorporated herein by
reference to the Proxy Statement.
| Item 13. | Certain Relationships and Related Transactions, and Director Independence. |
The information required by this Item is incorporated herein by
reference to the Proxy Statement.
| Item 14. | Principal Accountant Fees and Services. |
The information required by this Item is incorporated herein by
reference to the Proxy Statement.
34
Table of Contents
| Item 15. | Exhibits and Financial Statement Schedule. |
(a)(1)
Financial Statements
See Index to Consolidated Financial Statements on
page F-1
of this Report.
(a)(2)
Financial Statement Schedule
Schedule II — Valuation and qualifying accounts
is filed herewith on
page S-1.
All other financial statement schedules have been omitted
because they are not applicable or the information required
therein is included elsewhere in the financial statements or
notes thereto.
(a)(3)
Exhibits
The following exhibits are filed herewith or incorporated by
reference herein.
| 3 | .1 | Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference). | ||
| 3 | .2 | Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference). | ||
| 3 | .3 | Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference). | ||
| 4 | .1 | Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (filed January 14, 1997 as Exhibit 2 to the Company’s Registration Statement on Form 8-A and incorporated herein by reference). | ||
| 4 | .2 | Amendment to Rights Agreement dated as of October 23, 2001 (filed October 31, 2001 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001 and incorporated herein by reference). | ||
| 4 | .3 | Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2). | ||
| 4 | .4 | Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned by REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). | ||
| 10 | .1 | For additional material contracts, see Exhibits 4.1, 4.2 and 4.4. | ||
| 10 | .2 | Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).* | ||
| 10 | .3 | Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).* | ||
| 10 | .4 | Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).* | ||
| 10 | .5 | Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).* | ||
| 10 | .6 | Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by reference).* | ||
| 10 | .7 | First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). |
35
Table of Contents
| 10 | .8 | Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference). | ||
| 10 | .9 | Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time.* | ||
| 10 | .10 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .11 | Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on September 24, 2007 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by reference).* | ||
| 10 | .12 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .13 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .14 | Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III (filed on February 25, 2005 as Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).* | ||
| 10 | .15 | Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .16 | Severance Agreement between Patterson-UTI Energy, Inc. and Douglas J. Wall, effective as of August 31, 2007 (filed September 4, 2007 as Exhibit 10.3 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* | ||
| 10 | .17 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of August 31, 2007, by and between Patterson-UTI Energy, Inc. and Douglas J. Wall (filed September 4, 2007 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* | ||
| 10 | .18 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* | ||
| 10 | .19 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .20 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .21 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* |
36
Table of Contents
| 10 | .22 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .23 | Credit Agreement dated March 20, 2009, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC Bank USA, N.A., as lender, Bank of America, N.A., as syndication agent, letter of credit issuer and lender, and The Bank of Tokyo-Mitsubishi UFJ, Ltd. as documentation agent and lender (filed March 25, 2009 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). | ||
| 10 | .24 | Commitment Increase and Joinder Agreement dated June 19, 2009, among the Company, as borrower, Regions Bank as the new lender, Bank of America, N.A., as a letter of credit issuer and Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender (filed August 4, 2009 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference). | ||
| 10 | .25 | Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form 10-K, as amended, and incorporated herein by reference).* | ||
| 21 | .1 | Subsidiaries of the Registrant. | ||
| 23 | .1 | Consent of Independent Registered Public Accounting Firm. | ||
| 31 | .1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. | ||
| 31 | .2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. | ||
| 32 | .1 | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 101 | The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, (v) Notes to Consolidated Financial Statements, tagged as blocks of text, and (vi) Valuation and Qualifying Accounts. |
| * | Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. |
37
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||||||||
| F-2 | ||||||||
|
Consolidated Financial Statements:
|
||||||||
| F-3 | ||||||||
| F-4 | ||||||||
| F-5 | ||||||||
| F-6 | ||||||||
| F-7 | ||||||||
| S-1 | ||||||||
| EX-10.9 | ||||||||
| EX-21.1 | ||||||||
| EX-23.1 | ||||||||
| EX-31.1 | ||||||||
| EX-31.2 | ||||||||
| EX-32.1 | ||||||||
| EX-101 INSTANCE DOCUMENT | ||||||||
| EX-101 SCHEMA DOCUMENT | ||||||||
| EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
| EX-101 LABELS LINKBASE DOCUMENT | ||||||||
| EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
| EX-101 DEFINITION LINKBASE DOCUMENT | ||||||||
F-1
Table of Contents
Report of
Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Patterson-UTI Energy, Inc.:
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects,
the financial position of Patterson-UTI Energy, Inc. and its
subsidiaries (the “Company”) at December 31, 2009
and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended
December 31, 2009 in conformity with accounting principles
generally accepted in the United States of America. In addition,
in our opinion, the financial statement schedule listed in the
index appearing under Item 15(a)(2) presents fairly, in all
material respects, the information set forth therein when read
in conjunction with the related consolidated financial
statements. Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2009, based on criteria
established in
Internal Control — Integrated
Framework
issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The
Company’s management is responsible for these financial
statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting, included in Management’s Report on
Internal Control over Financial Reporting appearing under
Item 9A. Our responsibility is to express opinions on these
financial statements, on the financial statement schedule, and
on the Company’s internal control over financial reporting
based on our integrated audits. We conducted our audits in
accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we
plan and perform the audits to obtain reasonable assurance about
whether the financial statements are free of material
misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our
audits of the financial statements included examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also
included performing such other procedures as we considered
necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A company’s 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
generally accepted accounting principles. A company’s
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 generally accepted
accounting principles, 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.
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
February 19, 2010
F-2
Table of Contents
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
| December 31, | ||||||||
| 2009 | 2008 | |||||||
|
(In thousands,
|
||||||||
| except share data) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 49,877 | $ | 81,223 | ||||
|
Accounts receivable, net of allowance for doubtful accounts of
$10,911 and $9,330 at December 31, 2009 and 2008,
respectively
|
164,498 | 414,531 | ||||||
|
Federal and state income taxes receivable
|
118,869 | 10,175 | ||||||
|
Inventory
|
6,941 | 41,999 | ||||||
|
Deferred tax assets, net
|
32,877 | 35,928 | ||||||
|
Assets held for sale
|
42,424 | — | ||||||
|
Other
|
41,782 | 57,518 | ||||||
|
Total current assets
|
457,268 | 641,374 | ||||||
|
Property and equipment, net
|
2,110,402 | 1,937,112 | ||||||
|
Goodwill
|
86,234 | 86,234 | ||||||
|
Deposits on equipment purchases
|
914 | 43,944 | ||||||
|
Other
|
7,334 | 4,153 | ||||||
|
Total assets
|
$ | 2,662,152 | $ | 2,712,817 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable
|
$ | 83,700 | $ | 169,958 | ||||
|
Accrued expenses
|
109,608 | 132,655 | ||||||
|
Total current liabilities
|
193,308 | 302,613 | ||||||
|
Borrowings under revolving credit facility
|
— | — | ||||||
|
Deferred tax liabilities, net
|
381,656 | 277,717 | ||||||
|
Other
|
5,488 | 5,545 | ||||||
|
Total liabilities
|
580,452 | 585,875 | ||||||
|
Commitments and contingencies (see Note 9)
|
— | — | ||||||
|
Stockholders’ equity:
|
||||||||
|
Preferred stock, par value $.01; authorized
1,000,000 shares, no shares issued
|
— | — | ||||||
|
Common stock, par value $.01; authorized 300,000,000 shares
with 180,828,773 and 180,192,093 issued and 153,610,785 and
153,094,803 outstanding at December 31, 2009 and 2008,
respectively
|
1,808 | 1,801 | ||||||
|
Additional paid-in capital
|
781,635 | 765,512 | ||||||
|
Retained earnings
|
1,901,853 | 1,970,824 | ||||||
|
Accumulated other comprehensive income
|
14,996 | 5,774 | ||||||
|
Treasury stock, at cost, 27,217,988 shares and
27,097,290 shares at December 31, 2009 and 2008,
respectively
|
(618,592 | ) | (616,969 | ) | ||||
|
Total stockholders’ equity
|
2,081,700 | 2,126,942 | ||||||
|
Total liabilities and stockholders’ equity
|
$ | 2,662,152 | $ | 2,712,817 | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
Table of Contents
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
|
Operating revenues:
|
||||||||||||
|
Contract drilling
|
$ | 599,287 | $ | 1,804,026 | $ | 1,741,647 | ||||||
|
Pressure pumping
|
161,441 | 217,494 | 202,812 | |||||||||
|
Oil and natural gas
|
21,218 | 42,360 | 41,637 | |||||||||
|
Total operating revenues
|
781,946 | 2,063,880 | 1,986,096 | |||||||||
|
Operating costs and expenses:
|
||||||||||||
|
Contract drilling
|
357,742 | 1,038,327 | 963,150 | |||||||||
|
Pressure pumping
|
111,414 | 132,570 | 105,273 | |||||||||
|
Oil and natural gas
|
7,341 | 12,793 | 10,864 | |||||||||
|
Depreciation, depletion and impairment
|
289,847 | 275,990 | 246,346 | |||||||||
|
Selling, general and administrative
|
56,621 | 58,080 | 54,665 | |||||||||
|
Embezzlement recoveries
|
— | — | (43,955 | ) | ||||||||
|
Net loss (gain) on asset disposals
|
3,385 | (4,163 | ) | (16,432 | ) | |||||||
|
Other operating expenses
|
3,810 | 4,350 | 2,875 | |||||||||
|
Total operating costs and expenses
|
830,160 | 1,517,947 | 1,322,786 | |||||||||
|
Operating income (loss)
|
(48,214 | ) | 545,933 | 663,310 | ||||||||
|
Other income (expense):
|
||||||||||||
|
Interest income
|
381 | 1,553 | 2,351 | |||||||||
|
Interest expense
|
(4,148 | ) | (630 | ) | (2,187 | ) | ||||||
|
Other
|
426 | 502 | 363 | |||||||||
|
Total other income (expense)
|
(3,341 | ) | 1,425 | 527 | ||||||||
|
Income (loss) before income taxes
|
(51,555 | ) | 547,358 | 663,837 | ||||||||
|
Income tax expense (benefit):
|
||||||||||||
|
Current
|
(119,038 | ) | 128,098 | 191,028 | ||||||||
|
Deferred
|
101,443 | 65,392 | 38,322 | |||||||||
|
Total income tax expense (benefit)
|
(17,595 | ) | 193,490 | 229,350 | ||||||||
|
Income (loss) from continuing operations
|
(33,960 | ) | 353,868 | 434,487 | ||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
(4,330 | ) | (6,799 | ) | 4,152 | |||||||
|
Net income (loss)
|
$ | (38,290 | ) | $ | 347,069 | $ | 438,639 | |||||
|
Basic income (loss) per common share:
|
||||||||||||
|
Income (loss) from continuing operations
|
$ | (0.22 | ) | $ | 2.29 | $ | 2.78 | |||||
|
Income (loss) from discontinued operations, net of income taxes
|
(0.03 | ) | (0.04 | ) | 0.03 | |||||||
|
Net income (loss)
|
$ | (0.25 | ) | $ | 2.25 | $ | 2.81 | |||||
|
Diluted income (loss) per common share:
|
||||||||||||
|
Income (loss) from continuing operations
|
$ | (0.22 | ) | $ | 2.27 | $ | 2.75 | |||||
|
Income (loss) from discontinued operations, net of income taxes
|
(0.03 | ) | (0.04 | ) | 0.03 | |||||||
|
Net income (loss)
|
$ | (0.25 | ) | $ | 2.23 | $ | 2.78 | |||||
|
Weighted average number of common shares outstanding:
|
||||||||||||
|
Basic
|
152,069 | 153,379 | 154,755 | |||||||||
|
Diluted
|
152,069 | 154,358 | 156,612 | |||||||||
|
Cash dividends per common share
|
$ | 0.20 | $ | 0.60 | $ | 0.44 | ||||||
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
Table of Contents
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
|
Accumulated
|
||||||||||||||||||||||||||||||||
| Common Stock |
Additional
|
Other
|
||||||||||||||||||||||||||||||
|
Number of
|
Paid-in
|
Retained
|
Comprehensive
|
Treasury
|
||||||||||||||||||||||||||||
| Shares | Amount | Capital | Earnings | Income | Stock | Total | ||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
Balance, December 31, 2006
|
176,656 | $ | 1,766 | $ | 681,069 | $ | 1,346,542 | $ | 8,390 | $ | (475,301 | ) | $ | 1,562,466 | ||||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | — | 438,639 | — | — | 438,639 | |||||||||||||||||||||||||
|
Foreign currency translation adjustment, (net of tax of $6,755)
|
— | — | — | — | 11,817 | — | 11,817 | |||||||||||||||||||||||||
|
Total comprehensive income
|
— | — | — | 438,639 | 11,817 | — | 450,456 | |||||||||||||||||||||||||
|
Issuance of restricted stock
|
601 | 6 | (6 | ) | — | — | — | — | ||||||||||||||||||||||||
|
Forfeitures of restricted stock
|
(101 | ) | (1 | ) | 1 | — | — | — | — | |||||||||||||||||||||||
|
Exercise of stock options
|
230 | 2 | 2,048 | — | — | — | 2,050 | |||||||||||||||||||||||||
|
Stock-based compensation
|
— | — | 19,364 | — | — | — | 19,364 | |||||||||||||||||||||||||
|
Tax benefit related to stock-based compensation
|
— | — | 1,105 | — | — | — | 1,105 | |||||||||||||||||||||||||
|
Payment of cash dividends
|
— | — | — | (68,561 | ) | — | — | (68,561 | ) | |||||||||||||||||||||||
|
Purchase of treasury stock
|
— | — | — | — | — | (70,850 | ) | (70,850 | ) | |||||||||||||||||||||||
|
Balance, December 31, 2007
|
177,386 | 1,773 | 703,581 | 1,716,620 | 20,207 | (546,151 | ) | 1,896,030 | ||||||||||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | — | 347,069 | — | — | 347,069 | |||||||||||||||||||||||||
|
Foreign currency translation adjustment, (net of tax of $8,368)
|
— | — | — | — | (14,433 | ) | — | (14,433 | ) | |||||||||||||||||||||||
|
Total comprehensive income
|
— | — | — | 347,069 | (14,433 | ) | — | 332,636 | ||||||||||||||||||||||||
|
Issuance of restricted stock
|
577 | 6 | (6 | ) | — | — | — | — | ||||||||||||||||||||||||
|
Forfeitures of restricted stock
|
(75 | ) | (1 | ) | 1 | — | — | — | — | |||||||||||||||||||||||
|
Exercise of stock options
|
2,304 | 23 | 25,525 | — | — | — | 25,548 | |||||||||||||||||||||||||
|
Stock-based compensation
|
— | — | 20,131 | — | — | — | 20,131 | |||||||||||||||||||||||||
|
Tax benefit related to stock-based compensation
|
— | — | 16,280 | — | — | — | 16,280 | |||||||||||||||||||||||||
|
Payment of cash dividends
|
— | — | — | (92,865 | ) | — | — | (92,865 | ) | |||||||||||||||||||||||
|
Purchase of treasury stock
|
— | — | — | — | — | (70,818 | ) | (70,818 | ) | |||||||||||||||||||||||
|
Balance, December 31, 2008
|
180,192 | 1,801 | 765,512 | 1,970,824 | 5,774 | (616,969 | ) | 2,126,942 | ||||||||||||||||||||||||
|
Comprehensive income (loss):
|
||||||||||||||||||||||||||||||||
|
Net loss
|
— | — | — | (38,290 | ) | — | — | (38,290 | ) | |||||||||||||||||||||||
|
Foreign currency translation adjustment, (net of tax of $5,347)
|
— | — | — | — | 9,222 | — | 9,222 | |||||||||||||||||||||||||
|
Total comprehensive loss
|
— | — | — | (38,290 | ) | 9,222 | — | (29,068 | ) | |||||||||||||||||||||||
|
Issuance of restricted stock
|
604 | 6 | (6 | ) | — | — | — | — | ||||||||||||||||||||||||
|
Vesting of restricted stock units
|
6 | — | — | — | — | — | — | |||||||||||||||||||||||||
|
Forfeitures of restricted stock
|
(56 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||
|
Exercise of stock options
|
83 | 1 | 568 | — | — | — | 569 | |||||||||||||||||||||||||
|
Stock-based compensation
|
— | — | 18,565 | — | — | — | 18,565 | |||||||||||||||||||||||||
|
Tax expense related to stock-based compensation
|
— | — | (3,004 | ) | — | — | — | (3,004 | ) | |||||||||||||||||||||||
|
Payment of cash dividends
|
— | — | — | (30,681 | ) | — | — | (30,681 | ) | |||||||||||||||||||||||
|
Purchase of treasury stock
|
— | — | — | — | — | (1,623 | ) | (1,623 | ) | |||||||||||||||||||||||
|
Balance, December 31, 2009
|
180,829 | $ | 1,808 | $ | 781,635 | $ | 1,901,853 | $ | 14,996 | $ | (618,592 | ) | $ | 2,081,700 | ||||||||||||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
Table of Contents
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Net income (loss)
|
$ | (38,290 | ) | $ | 347,069 | $ | 438,639 | |||||
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
||||||||||||
|
Depreciation, depletion and impairment
|
289,847 | 275,990 | 246,346 | |||||||||
|
Provision for bad debts
|
3,810 | 4,350 | 2,875 | |||||||||
|
Dry holes and abandonments
|
129 | 1,617 | 1,309 | |||||||||
|
Deferred income tax expense
|
101,443 | 65,392 | 38,322 | |||||||||
|
Stock-based compensation expense
|
18,214 | 19,688 | 18,873 | |||||||||
|
Net loss (gain) on asset disposals
|
3,385 | (4,163 | ) | (16,432 | ) | |||||||
|
Tax expense related to stock-based compensation
|
(3,004 | ) | — | — | ||||||||
|
Changes in operating assets and liabilities:
|
||||||||||||
|
Accounts receivable
|
213,813 | (30,777 | ) | 100,429 | ||||||||
|
Income taxes receivable/payable
|
(108,664 | ) | (11,258 | ) | 7,174 | |||||||
|
Inventory and other assets
|
14,178 | 2,498 | 2,211 | |||||||||
|
Accounts payable
|
(52,673 | ) | 6,486 | (37,412 | ) | |||||||
|
Accrued expenses
|
(21,178 | ) | (4,474 | ) | (5,640 | ) | ||||||
|
Other liabilities
|
(92 | ) | 1,242 | 1,434 | ||||||||
|
Net cash provided by operating activities of discontinued
operations
|
32,759 | 1,344 | 14,096 | |||||||||
|
Net cash provided by operating activities
|
453,677 | 675,004 | 812,224 | |||||||||
|
Cash flows from investing activities:
|
||||||||||||
|
Acquisitions
|
— | — | (29,000 | ) | ||||||||
|
Purchases of property and equipment
|
(452,646 | ) | (445,426 | ) | (604,604 | ) | ||||||
|
Proceeds from disposal of assets
|
3,359 | 11,436 | 34,054 | |||||||||
|
Net cash used in investing activities of discontinued operations
|
(54 | ) | (3,286 | ) | (2,912 | ) | ||||||
|
Net cash used in investing activities
|
(449,341 | ) | (437,276 | ) | (602,462 | ) | ||||||
|
Cash flows from financing activities:
|
||||||||||||
|
Purchases of treasury stock
|
(1,623 | ) | (70,818 | ) | (70,850 | ) | ||||||
|
Dividends paid
|
(30,681 | ) | (92,865 | ) | (68,561 | ) | ||||||
|
Tax benefit related to stock-based compensation
|
— | 16,280 | 1,105 | |||||||||
|
Proceeds from borrowings under revolving credit facility
|
— | — | 142,500 | |||||||||
|
Repayment of borrowings under revolving credit facility
|
— | (50,000 | ) | (212,500 | ) | |||||||
|
Revolving credit facility issuance costs
|
(6,169 | ) | — | — | ||||||||
|
Proceeds from exercise of stock options
|
569 | 25,548 | 2,050 | |||||||||
|
Net cash used in financing activities
|
(37,904 | ) | (171,855 | ) | (206,256 | ) | ||||||
|
Effect of foreign exchange rate changes on cash
|
2,222 | (2,084 | ) | 543 | ||||||||
|
Net increase (decrease) in cash and cash equivalents
|
(31,346 | ) | 63,789 | 4,049 | ||||||||
|
Cash and cash equivalents at beginning of year
|
81,223 | 17,434 | 13,385 | |||||||||
|
Cash and cash equivalents at end of year
|
$ | 49,877 | $ | 81,223 | $ | 17,434 | ||||||
|
Supplemental disclosure of cash flow information:
|
||||||||||||
|
Net cash (paid) received during the year for:
|
||||||||||||
|
Interest expense
|
$ | (1,804 | ) | $ | (323 | ) | $ | (1,808 | ) | |||
|
Income taxes
|
14,029 | (126,331 | ) | (176,281 | ) | |||||||
|
Non-cash investing and financing activities:
|
||||||||||||
|
Net increase (decrease) in payables for purchases of property
and equipment
|
$ | (25,110 | ) | $ | (3,590 | ) | $ | 597 | ||||
|
Net (increase) decrease in deposits on equipment purchases
|
43,029 | (42,293 | ) | 23,095 | ||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
Table of Contents
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
| 1. | Description of Business and Summary of Significant Accounting Policies |
A
description of the business and basis of presentation
follows:
Description of business
— Patterson-UTI Energy,
Inc., through its wholly-owned subsidiaries (collectively
referred to herein as “Patterson-UTI” or the
“Company”), is a leading provider of onshore contract
drilling services to major and independent oil and natural gas
operators in Texas, New Mexico, Oklahoma, Arkansas, Louisiana,
Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota,
Pennsylvania, West Virginia and western Canada. The Company
provides pressure pumping services primarily in the Appalachian
Basin. The Company also owns and invests in oil and natural gas
assets as a working interest owner primarily in Texas and New
Mexico.
Basis of presentation
— The consolidated
financial statements include the accounts of Patterson-UTI and
its wholly-owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated. Except for
wholly-owned subsidiaries, the Company has no controlling
financial interests in any entity which would require
consolidation.
The U.S. dollar is the functional currency for all of the
Company’s operations except for its Canadian operations,
which use the Canadian dollar as its functional currency. The
effects of exchange rate changes are reflected in accumulated
other comprehensive income, which is a separate component of
stockholders’ equity.
A
summary of the significant accounting policies
follows:
Management estimates
— The preparation of
financial statements in conformity with accounting principles
generally accepted in the United States of America requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
such estimates.
Revenue recognition
— Revenues are recognized
when services are performed, except for revenues earned under
turnkey contract drilling arrangements which are recognized
using the completed contract method of accounting. The Company
follows the
percentage-of-completion
method of accounting for footage contract drilling arrangements.
Under the
percentage-of-completion
method, management estimates are relied upon in the
determination of the total estimated expenses to be incurred
drilling the well. Due to the nature of turnkey contract
drilling arrangements and risks therein, the Company follows the
completed contract method of accounting for such arrangements.
Under this method, all drilling revenues and expenses related to
a well in progress are deferred and recognized in the period the
well is completed. Provisions for losses on incomplete or
in-process wells are made when estimated total expenses are
expected to exceed estimated total revenues. The Company
recognizes reimbursements received from third parties for
out-of-pocket
expenses incurred as revenues and accounts for these
out-of-pocket
expenses as direct costs. Except for two wells drilled under
footage contracts in 2009, all of the wells the Company drilled
during the years ended December 31, 2009, 2008 and 2007
were under daywork contracts.
Accounts receivable
— Trade accounts receivable
are recorded at the invoiced amount. The allowance for doubtful
accounts represents the Company’s estimate of the amount of
probable credit losses existing in the Company’s accounts
receivable. The Company reviews the adequacy of its allowance
for doubtful accounts at least quarterly. Significant individual
accounts receivable balances and balances which have been
outstanding greater than 90 days are reviewed individually
for collectibility. Account balances, when determined to be
uncollectible, are charged against the allowance.
Inventories
— Inventories at December 31,
2009 consist primarily of chemical products and sand to be used
in conjunction with the Company’s pressure pumping
activities. Inventories at December 31, 2008 consisted
primarily of chemical products to be used in conjunction with
the Company’s drilling and completion fluids activities.
The inventories are stated at the lower of cost or market,
determined by the
first-in,
first-out method.
F-7
Table of Contents
Property and equipment
— Property and equipment
is carried at cost less accumulated depreciation. Depreciation
is provided on the straight-line method over the estimated
useful lives. The method of depreciation does not change when
equipment becomes idle. The estimated useful lives, in years,
are shown below:
| Useful Lives | ||||
|
Drilling rigs and other equipment
|
2-15 | |||
|
Buildings
|
15-20 | |||
|
Other
|
3-12 | |||
Long-lived assets, including property and equipment, are
evaluated for impairment when certain triggering events or
changes in circumstances indicate that the carrying values may
not be recoverable over their estimated remaining useful life.
Oil and natural gas properties
— Working
interests in oil and natural gas properties are accounted for
using the successful efforts method of accounting. Under the
successful efforts method of accounting, exploration costs which
result in the discovery of oil and natural gas reserves and all
development costs are capitalized to the appropriate well.
Exploration costs which do not result in discovering oil and
natural gas reserves are charged to expense when such
determination is made. Costs of exploratory wells are initially
capitalized to wells in progress until the outcome of the
drilling is known. The Company reviews wells in progress
quarterly to determine whether sufficient progress is being made
in assessing the reserves and the economic operating viability
of the respective projects. If no progress has been made in
assessing the reserves and the economic operating viability of a
project after one year following the completion of drilling, the
Company considers the costs of the well to be impaired and
recognizes the costs as expense. Geological and geophysical
costs, including seismic costs, and costs to carry and retain
undeveloped properties are charged to expense when incurred. The
capitalized costs of both developmental and successful
exploratory type wells, consisting of lease and well equipment,
lease acquisition costs and intangible development costs, are
depreciated, depleted and amortized on the
units-of-production
method, based on engineering estimates of proved oil and natural
gas reserves of each respective field.
The Company reviews its proved oil and natural gas properties
for impairment when a triggering event occurs such as downward
revisions in reserve estimates or decreases in oil and natural
gas prices. Proved properties are grouped by field and
undiscounted cash flow estimates are prepared based on
management’s expectation of future pricing over the lives
of the respective fields. These estimates are then reviewed by
an independent petroleum engineer. If the net book value of a
field exceeds its undiscounted cash flow estimate, impairment
expense is measured and recognized as the difference between its
net book value and discounted cash flow. Unproved oil and
natural gas properties are reviewed quarterly to assess
potential impairment. The Company’s intent to drill, lease
expiration and abandonment of area are considered. Assessment of
impairment is made on a
lease-by-lease
basis. If an unproved property is determined to be impaired,
costs related to that property are expensed.
Goodwill
— Goodwill is considered to have an
indefinite useful economic life and is not amortized. The
Company assesses impairment of its goodwill at least annually or
on an interim basis if triggering events or circumstances
indicate that the fair value of the asset may have decreased
below its carrying value. As discussed in Note 5, the
Company determined that goodwill in its drilling and completion
fluids reporting unit was impaired in connection with its annual
impairment testing performed as of December 31, 2008. As
discussed in Note 2, the Company exited the drilling and
completion fluids business in January 2010, and this impairment
charge is included in the results of discontinued operations in
the consolidated statements of operations for the year ended
December 31, 2008.
Maintenance and repairs
— Maintenance and
repairs are charged to expense when incurred. Renewals and
betterments which extend the life or improve existing property
and equipment are capitalized.
Disposals
— Upon disposition of property and
equipment, the cost and related accumulated depreciation are
removed and any resulting gain or loss is reflected in the
consolidated statement of operations.
Net income (loss) per common share
— The
Company provides a dual presentation of its net income (loss)
per common share in its consolidated statements of operations:
Basic net income (loss) per common share (“Basic EPS”)
and diluted net income (loss) per common share (“Diluted
EPS”). The Company adopted a new accounting standard on
January 1, 2009, which clarified that share-based payment
awards that entitle their holders to receive
F-8
Table of Contents
non-forfeitable dividends before vesting should be considered
participating securities and, as such, should be included in the
calculation of
earnings-per-share
using the two-class method. All
earnings-per-share
data presented for the years ended December 31, 2008 and
2007 have been adjusted retrospectively to conform with this
accounting standard. The impact of this retrospective
application to the year ended December 31, 2008 was to
reduce Basic and Diluted EPS by $0.01. The impact of this
retrospective application to the year ended December 31,
2007 was to reduce Basic EPS by $0.02 and to reduce Diluted EPS
by $0.01.
Basic EPS excludes dilution and is computed by first allocating
earnings between common stockholders and holders of non-vested
shares of restricted stock. Basic EPS is then determined by
dividing the earnings attributable to common stockholders by the
weighted average number of common shares outstanding during the
period, excluding non-vested shares of restricted stock.
Diluted EPS is based on the weighted average number of common
shares outstanding plus the dilutive effect of potential common
shares, including stock options, non-vested shares of restricted
stock and restricted stock units. The dilutive effect of stock
options and restricted stock units is determined using the
treasury stock method. The dilutive effect of non-vested shares
of restricted stock is based on the more dilutive of the
treasury stock method or the two-class method, assuming a
reallocation of undistributed earnings to common stockholders
after considering the dilutive effect of potential common shares
other than non-vested shares of restricted stock.
The following table presents information necessary to calculate
income (loss) from continuing operations per share, income(loss)
from discontinued operations per share and net income (loss) per
share for the years ended December 31, 2009, 2008 and 2007
as well as potentially dilutive securities excluded from the
weighted average number of diluted common shares outstanding, as
their inclusion would have been anti-dilutive (in thousands,
except per share amounts):
| 2009 | 2008 | 2007 | ||||||||||
|
BASIC EPS:
|
||||||||||||
|
Income (loss) from continuing operations
|
$ | (33,960 | ) | $ | 353,868 | $ | 434,487 | |||||
|
Adjust for (income) loss attributed to holders of non-vested
restricted stock
|
313 | (3,279 | ) | (3,886 | ) | |||||||
|
Income (loss) from continuing operations attributed to common
stockholders
|
$ | (33,647 | ) | $ | 350,589 | $ | 430,601 | |||||
|
Income (loss) from discontinued operations, net
|
$ | (4,330 | ) | $ | (6,799 | ) | $ | 4,152 | ||||
|
Adjust for (income) loss attributed to holders of non-vested
restricted stock
|
38 | 64 | (37 | ) | ||||||||
|
Income (loss) from discontinued operations attributed to common
stockholders
|
$ | (4,292 | ) | $ | (6,735 | ) | $ | 4,115 | ||||
|
Weighted average number of common shares outstanding, excluding
non-vested shares of restricted stock
|
152,069 | 153,379 | 154,755 | |||||||||
|
Basic income (loss) from continuing operations per common share
|
$ | (0.22 | ) | $ | 2.29 | $ | 2.78 | |||||
|
Basic income (loss) from discontinued operations per common share
|
(0.03 | ) | (0.04 | ) | 0.03 | |||||||
|
Basic net income (loss) per common share
|
$ | (0.25 | ) | $ | 2.25 | $ | 2.81 | |||||
F-9
Table of Contents
| 2009 | 2008 | 2007 | ||||||||||
|
DILUTED EPS:
|
||||||||||||
|
Income (loss) from continuing operations attributed to common
stockholders
|
$ | (33,647 | ) | $ | 350,589 | $ | 430,601 | |||||
|
Add incremental earnings related to potential common shares
|
— | 15 | 39 | |||||||||
|
Adjusted income (loss) from continuing operations attributed to
common stockholders
|
$ | (33,647 | ) | $ | 350,604 | $ | 430,640 | |||||
|
Weighted average number of common shares outstanding, excluding
non-vested shares of restricted stock
|
152,069 | 153,379 | 154,755 | |||||||||
|
Add dilutive effect of potential common shares
|
— | 979 | 1,857 | |||||||||
|
Weighted average number of diluted common shares outstanding
|
152,069 | 154,358 | 156,612 | |||||||||
|
Diluted income (loss) from continuing operations per common share
|
$ | (0.22 | ) | $ | 2.27 | $ | 2.75 | |||||
|
Diluted income (loss) from discontinued operations per common
share
|
(0.03 | ) | (0.04 | ) | 0.03 | |||||||
|
Diluted net income (loss) per common share
|
$ | (0.25 | ) | $ | 2.23 | $ | 2.78 | |||||
|
Potentially dilutive securities excluded as anti-dilutive
|
8,090 | 2,455 | 2,460 | |||||||||
Income taxes
— The asset and liability method
is used in accounting for income taxes. Under this method,
deferred tax assets and liabilities are recognized for operating
loss and tax credit carryforwards and for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities
and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates expected to
apply to taxable income in the year in which those temporary
differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates
is recognized in the results of operations in the period that
includes the enactment date. If applicable, a valuation
allowance is recorded to reduce the carrying amounts of deferred
tax assets unless it is more likely than not that such assets
will be realized.
The Company adopted a new accounting standard on January 1,
2007 which clarified the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements
and prescribed a recognition threshold and measurement attribute
for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. As a
result of the adoption of this standard in 2007, the Company
reduced a reserve for an uncertain tax position related to a
prior business combination that had originally been recorded as
goodwill in its contract drilling segment. The impact of this
adjustment was to reduce goodwill in the contract drilling
segment by approximately $2.9 million upon adoption of the
new standard. The impact of adjustments to reserves with respect
to other uncertain tax positions was not material. The
Company’s policy is to account for interest and penalties
with respect to income taxes as operating expenses.
Stock based compensation
— The Company
recognizes the cost of share-based payments under the
fair-value-based method. Under this method, compensation cost
related to share-based payments is measured based on the
estimated fair value of the awards at the date of grant, net of
estimated forfeitures. This expense is recognized over the
expected life of the awards (See Note 11).
Statement of cash flows
— For purposes of
reporting cash flows, cash and cash equivalents include cash on
deposit and money market funds.
Subsequent Events
— The Company has performed
an evaluation of subsequent events through February 19, 2010 at
the time of issuance of the consolidated financial statements.
Recently Issued Accounting Standards
— In June
2008, the FASB issued an accounting standard which clarifies
that share-based payment awards that entitle their holders to
receive non-forfeitable dividends before
F-10
Table of Contents
vesting should be considered participating securities and, as
such, should be included in the calculation of basic
earnings-per-share
using the two-class method. Certain of the Company’s
share-based payment awards entitle the holders to receive
non-forfeitable dividends. This standard is effective for
financial statements issued for fiscal years beginning after
December 15, 2008, as well as interim periods within those
years, and became effective for the Company on January 1,
2009. The impact of the adoption of this standard is discussed
in this Note 1.
In December 2008, the SEC issued a Final Rule,
Modernization
of Oil and Gas Reporting
(“Final Rule”). The Final
Rule revises certain 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. The amendments are designed to modernize and
update oil and gas disclosure requirements to align them with
current practices and changes in technology. 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 Company
applied the provisions of the Final Rule in connection with its
December 31, 2009 oil and natural gas reserve estimation
process. The application of the Final Rule did not have a
material impact on the Company.
In April 2009, the FASB issued a staff position to provide
additional guidance for determining whether a market for a
financial asset is not active and a transaction is not
distressed for fair value measurements under generally accepted
accounting principles. The provisions of this staff position are
effective for financial statements issued for interim and annual
periods ending after June 15, 2009 and became effective for
the Company in the quarter ended June 30, 2009. The
adoption of this staff position did not have a material impact
on the Company.
In June 2009, the FASB issued a new accounting standard that
amends the accounting and disclosure requirements for the
consolidation of variable interest entities. This new standard
removes the previously existing exception from applying
consolidation guidance to qualifying special-purpose entities
and requires ongoing reassessments of whether an enterprise is
the primary beneficiary of a variable interest entity. Before
this new standard, generally accepted accounting principles
required reconsideration of whether an enterprise is the primary
beneficiary of a variable interest entity only when specific
events occurred. This new standard is effective as of the
beginning of each reporting entity’s first annual reporting
period that begins after November 15, 2009, for interim
periods within that first annual reporting period, and for
interim and annual reporting periods thereafter. This new
standard became effective for the Company on January 1,
2010. The adoption of this standard did not impact the
Company’s consolidated financial statements.
In June 2009, the FASB issued the FASB Accounting Standards
Codification (“Codification”). Effective for financial
statements issued for interim and annual periods ending after
September 15, 2009, the Codification became the source of
authoritative U.S. generally accepted accounting
principles. The FASB will no longer issue new standards in the
form of Statements, FASB Staff Positions or EITF Abstracts.
Instead, it will issue Accounting Standards Updates to update
the Codification. The adoption of the Codification did not
impact the Company’s consolidated financial statements.
Reclassifications
— Certain reclassifications
have been made to the 2008 and 2007 consolidated financial
statements in order for them to conform with the 2009
presentation. These reclassifications had no impact on the
Company’s financial position, results of operations or cash
flows.
| 2. | Discontinued Operations |
On January 20, 2010, the Company exited the drilling and
completion fluids services business, which had previously been
presented as one of the Company’s reportable operating
segments. On that date, the Company’s wholly owned
subsidiary, Ambar Lone Star Fluids Services LLC, completed the
sale of substantially all of its assets, excluding billed
accounts receivable. The sales price was approximately
$44.3 million, subject to any post-closing adjustments to
reflect the actual assets transferred as of the closing date.
Upon the Company’s exit from the drilling and completion
fluids services business, the Company classified its drilling
and completion fluids operating segment as a discontinued
operation. Accordingly, the results of operations of this
business have been reclassified and presented as results of
discontinued operations for all periods presented in these
consolidated financial statements. As of December 31, 2009,
the assets to be disposed of are considered held for sale and
are presented separately under the caption “Assets held for
sale” in the consolidated balance sheet. These assets are
included in the balance sheet at fair value less transaction
costs. The fair value of the assets to be disposed of was
estimated to be
F-11
Table of Contents
approximately $44.3 million based on the expected sales
price described above. The source of this estimate was from a
third party and it is considered a level 2 input in the fair
value hierarchy of fair value accounting. Costs to sell the
disposal group were estimated to be $1.9 million. An impairment
charge of $1.9 million was recognized to reduce the carrying
value of the disposal group to its estimated fair value less
costs to sell.
Summarized operating results from discontinued operations for
the years ended December 31, 2009, 2008 and 2007 are shown
below (in thousands):
| 2009 | 2008 | 2007 | ||||||||||
|
Drilling and completion fluids revenues
|
$ | 79,786 | $ | 145,246 | $ | 128,098 | ||||||
|
Income (loss) before income taxes
|
$ | (6,538 | ) | $ | (4,410 | ) | $ | 6,970 | ||||
|
Income tax benefit (expense)
|
2,208 | (2,389 | ) | (2,818 | ) | |||||||
|
Income (loss) from discontinued operations
|
$ | (4,330 | ) | $ | (6,799 | ) | $ | 4,152 | ||||
The loss before income taxes in 2008 includes $9.96 million
in non-deductible charges resulting from the impairment of
goodwill. As a result, income tax expense was incurred for the
year despite the fact that the discontinued operation had a
pre-tax book loss.
The components of assets held for sale at December 31, 2009
are shown below (in thousands):
|
Assets held for sale:
|
||||
|
Inventory
|
$ | 28,620 | ||
|
Unbilled accounts receivable
|
6,587 | |||
|
Prepaid expenses and other current assets
|
324 | |||
|
Property and equipment, net
|
8,793 | |||
|
Reserve to reduce disposal group to fair value less costs to sell
|
(1,900 | ) | ||
|
Total assets held for sale
|
$ | 42,424 | ||
| 3. | Acquisitions |
On October 9, 2007, the Company acquired three recently
refurbished SCR electric land-based drilling rigs and spare
drilling equipment for $29.0 million. The transaction was
accounted for as an acquisition of assets and the purchase price
was allocated among the assets acquired based on their estimated
fair market values.
| 4. | Property and Equipment |
Property and equipment consisted of the following at
December 31, 2009 and 2008 (in thousands):
| 2009 | 2008 | |||||||
|
Equipment
|
$ | 3,230,737 | $ | 2,897,431 | ||||
|
Oil and natural gas properties
|
93,354 | 89,809 | ||||||
|
Buildings
|
56,563 | 61,529 | ||||||
|
Land
|
9,795 | 10,196 | ||||||
| 3,390,449 | 3,058,965 | |||||||
|
Less accumulated depreciation and depletion
|
(1,280,047 | ) | (1,121,853 | ) | ||||
|
Property and equipment, net
|
$ | 2,110,402 | $ | 1,937,112 | ||||
F-12
Table of Contents
Depreciation, depletion and impairment
— The
following table summarizes depreciation, depletion and
impairment expense related to property and equipment for 2009,
2008 and 2007 (in millions):
| 2009 | 2008 | 2007 | ||||||||||
|
Depreciation and impairment expense
|
$ | 280.6 | $ | 264.5 | $ | 232.9 | ||||||
|
Depletion expense
|
9.2 | 11.5 | 13.4 | |||||||||
|
Total
|
$ | 289.8 | $ | 276.0 | $ | 246.3 | ||||||
The Company evaluates the recoverability of its long-lived
assets whenever events or changes in circumstances indicate that
their carrying amounts may not be recoverable. In light of
adverse market conditions affecting the Company beginning in the
fourth quarter of 2008 and continuing into 2009, including a
substantial decrease in the operating levels of certain of its
business segments, a significant decline in oil and natural gas
commodity prices, and the results of the Company’s annual
goodwill impairment test at December 31, 2008 (see
Note 5), the Company deemed it necessary to assess the
recoverability of long-lived assets within its contract drilling
and drilling and completion fluids segments in 2008. Due to a
continued decrease in the operating levels in its contract
drilling business segment through the first three quarters of
2009, the Company again deemed it necessary to assess the
recoverability of long-lived assets within that segment during
2009. With respect to the long-lived assets in the
Company’s oil and natural gas exploration and production
segment, the Company assesses the recoverability of long-lived
assets at the end of each quarter due to revisions in its oil
and natural gas reserve estimates and expectations about future
commodity prices. The Company concluded that its pressure
pumping segment was not subject to the negative events and
trends, to the same degree as the contract drilling segment, and
thus did not require further assessment of recoverability.
The Company performs the first step of its impairment
assessments by comparing the undiscounted cash flows for each
long-lived asset or asset group to its respective carrying
value. Based on the results of these impairment tests, the
carrying amounts of long-lived assets in the contract drilling
and oil and natural gas segments were determined to be
recoverable, except as described below.
The Company’s analysis indicated that the carrying amounts
of certain oil and natural gas properties were not recoverable
at various testing dates in 2009, 2008 and 2007. The
Company’s estimates of expected future net cash flows from
impaired properties are used in measuring the fair value of such
properties. The Company recorded impairment charges of
$3.7 million, $4.4 million and $3.9 million in
2009, 2008 and 2007, respectively, related to its oil and
natural gas properties. The Company determined the fair value of
the impaired assets using internally developed unobservable
inputs (level 3 inputs in the fair value hierarchy of fair value
accounting).
During 2009 and 2008, in connection with its long term planning
process, the Company evaluated its then-current fleet of
marketable drilling rigs and identified 23 and 22 rigs,
respectively, that it determined would no longer be marketed as
rigs. Additionally, in 2009, the Company identified one rig
which would be recommissioned in a different configuration. The
components comprising these rigs were evaluated, and those
components with continuing utility to the Company’s other
marketed rigs were transferred to other rigs or to yards to be
used as spare equipment. The remaining components of these rigs
were impaired and the associated net book value of
$10.5 million in 2009 and $10.4 million in 2008 was
expensed in the Company’s consolidated statements of
operations as an impairment charge. The components that were
impaired were estimated to have no fair value. The Company
determined the fair value of the impaired assets using
internally developed unobservable inputs (level 3 inputs in the
fair value hierarchy of fair value accounting).
F-13
Table of Contents
| 5. | Goodwill |
Goodwill by operating segment as of December 31, 2009 and
2008 and changes for the years then ended are as follows (in
thousands):
| 2009 | 2008 | |||||||
|
Contract Drilling:
|
||||||||
|
Balance as of January 1:
|
||||||||
|
Goodwill
|
$ | 86,234 | $ | 86,234 | ||||
|
Accumulated impairment losses
|
— | — | ||||||
| 86,234 | 86,234 | |||||||
|
Changes to goodwill
|
— | — | ||||||
|
Balance as of December 31:
|
||||||||
|
Goodwill
|
86,234 | 86,234 | ||||||
|
Accumulated impairment losses
|
— | — | ||||||
| 86,234 | 86,234 | |||||||
|
Drilling and Completion Fluids (Discontinued Operations):
|
||||||||
|
Balance as of January 1:
|
||||||||
|
Goodwill
|
9,964 | 9,964 | ||||||
|
Accumulated impairment losses
|
(9,964 | ) | — | |||||
| — | 9,964 | |||||||
|
Impairment
|
— | (9,964 | ) | |||||
|
Balance as of December 31:
|
||||||||
|
Goodwill
|
9,964 | 9,964 | ||||||
|
Accumulated impairment losses
|
(9,964 | ) | (9,964 | ) | ||||
| — | — | |||||||
|
Total goodwill as of December 31
|
$ | 86,234 | $ | 86,234 | ||||
Goodwill is evaluated at least annually to determine if the fair
value of recorded goodwill has decreased below its carrying
value. For purposes of impairment testing, goodwill is evaluated
at the reporting unit level. The Company’s reporting units
for impairment testing have been determined to be its operating
segments. Goodwill as of December 31, 2009 and 2008 is
recorded in the Company’s contract drilling segment. Prior
to 2008, goodwill was also recorded in the Company’s
drilling and completion fluids segment.
In connection with its annual goodwill impairment assessment
performed as of December 31, 2008, the Company performed an
impairment test of goodwill recorded in its contract drilling
and drilling and completion fluids reporting units. In light of
the adverse market conditions affecting the Company’s
common stock price beginning in the fourth quarter of 2008 and
continuing into 2009, including a significant decrease in the
number of its rigs operating and a significant decline in oil
and natural gas commodity prices, the Company utilized a
discounted cash flow methodology to estimate the fair values of
its reporting units. In completing its first step of the
analysis, the Company used a three-year projection of discounted
cash flows, plus a terminal value determined using the constant
growth method to estimate the fair value of its reporting units.
In developing these fair value estimates, the Company applied
key assumptions, including an assumed discount rate of 13.99%
for all reporting units, an assumed long-term growth rate of
3.50% for the contract drilling reporting unit and an assumed
long-term growth rate of 2.00% for the drilling and completion
fluids reporting unit.
Based on the results of the first step of the impairment test in
2008, the Company concluded that no impairment was indicated in
its contract drilling reporting unit as the estimated fair value
of that reporting unit exceeded its carrying value. An
impairment was indicated in the drilling and completion fluids
reporting unit as the estimated fair value of that reporting
unit was less than its carrying value. In validating this
conclusion, the Company considered the results of its long-lived
asset impairment tests and performed sensitivity analyses of the
key assumptions used in deriving the respective fair values of
its reporting units. The Company then performed the second step
of the analysis of its drilling and completion fluids reporting
unit, which included allocating the
F-14
Table of Contents
estimated fair value to the identifiable tangible and intangible
assets and liabilities of this reporting unit based on their
respective values. This allocation indicated that there was no
residual value for goodwill, and accordingly the Company
recorded an impairment charge of $9.964 million in the year
ended December 31, 2008. As discussed in Note 2, the
Company exited the drilling and completion fluids business on
January 20, 2010, and the impairment charge recorded in
2008 is included in the loss from discontinued operations in the
Company’s statement of operations for the year ended
December 31, 2008.
The Company again performed its annual goodwill impairment
assessment as of December 31, 2009 related to the remaining
$86.2 million in goodwill recorded in its contract drilling
reporting unit. In completing its first step of the analysis,
the Company used a three-year projection of discounted cash
flows, plus a terminal value determined using the constant
growth method to estimate the fair value of the reporting unit.
In developing this fair value estimate, the Company applied key
assumptions, including an assumed discount rate of 15.42% and an
assumed long-term growth rate of 3.50%. Based on the results of
the first step of the impairment test in 2009, the Company
concluded that no impairment was indicated in its contract
drilling reporting unit as the estimated fair value of that
reporting unit exceeded its carrying value.
In the event that market conditions weaken, the Company may be
required to record an impairment of goodwill in its contract
drilling reporting unit in the future, and such impairment could
be material.
| 6. | Accrued Expenses |
Accrued expenses consisted of the following at December 31,
2009 and 2008 (in thousands):
| 2009 | 2008 | |||||||
|
Salaries, wages, payroll taxes and benefits
|
$ | 14,744 | $ | 30,334 | ||||
|
Workers’ compensation liability
|
66,015 | 70,439 | ||||||
|
Sales, use and other taxes
|
10,975 | 12,105 | ||||||
|
Insurance, other than workers’ compensation
|
11,261 | 14,209 | ||||||
|
Other
|
6,613 | 5,658 | ||||||
| $ | 109,608 | $ | 132,655 | |||||
| 7. | Asset Retirement Obligation |
The Company records a liability for the estimated costs to be
incurred in connection with the abandonment of oil and natural
gas properties in the future. This liability is included in the
caption “other liabilities” on the consolidated
balance sheet. The following table describes the changes to the
Company’s asset retirement obligations during 2009 and 2008
(in thousands):
| 2009 | 2008 | |||||||
|
Balance at beginning of year
|
$ | 3,047 | $ | 1,593 | ||||
|
Liabilities incurred
|
157 | 516 | ||||||
|
Liabilities settled
|
(354 | ) | (424 | ) | ||||
|
Accretion expense
|
118 | 59 | ||||||
|
Revision in estimated costs of plugging oil and natural gas wells
|
(13 | ) | 1,303 | |||||
|
Asset retirement obligation at end of year
|
$ | 2,955 | $ | 3,047 | ||||
| 8. | Borrowings Under Revolving Credit Facility |
In March 2009, the Company entered into an unsecured revolving
credit facility with a maximum borrowing capacity of
$240 million, including a letter of credit sublimit of
$150 million and a swing line sublimit of $40 million.
In addition, the aggregate borrowing and letter of credit
capacity under the revolving credit facility may, subject to the
terms and conditions set forth therein including the receipt of
additional commitments from lenders, be increased up to a
maximum amount not to exceed $450 million.
F-15
Table of Contents
Interest is paid on the outstanding principal amount of
revolving credit facility borrowings at a floating rate based
on, at the Company’s election, LIBOR or a base rate. The
margin on LIBOR loans ranges from 3.00% to 4.00% and the margin
on base rate loans ranges from 2.00% to 3.00%, based on the
Company’s debt to capitalization ratio. At
December 31, 2009, the margin on LIBOR loans would have
been 3.00% and the margin on base rate loans would have been
2.00%. Any outstanding borrowings must be repaid at maturity on
January 31, 2012 and letters of credit may remain in effect
up to six months after such maturity date. This revolving credit
facility includes various fees, including a commitment fee on
the actual daily unused commitment (the commitment fee rate was
1.00% at December 31, 2009).
The Company incurred line of credit issuance costs of
approximately $6.2 million during 2009 in connection with
the revolving credit facility. These costs are being amortized
to interest expense over the contractual term of the revolving
credit facility.
There are customary representations, warranties, restrictions
and covenants associated with the revolving credit facility.
Financial covenants provide for a maximum debt to capitalization
ratio and a minimum interest coverage ratio. As of
December 31, 2009, the maximum debt to capitalization ratio
was 35% and the minimum interest coverage ratio was 3.00 to 1.
The Company does not expect that the restrictions and covenants
will impact its ability to operate or react to opportunities
that might arise.
As of December 31, 2009, the Company had no borrowings
outstanding under the revolving credit facility. The Company had
$46.3 million in letters of credit outstanding at
December 31, 2009 and, as a result, had available borrowing
capacity of approximately $194 million at that date. Each
domestic subsidiary of the Company has unconditionally
guaranteed the existing and future obligations of the Company
and each other guarantor under the revolving credit facility and
related loan documents, as well as obligations of the Company
and its subsidiaries under any interest rate swap contracts that
may be entered into with lenders party to the revolving credit
facility.
| 9. | Commitments, Contingencies and Other Matters |
Commitments —
As of December 31, 2009, the
Company maintained letters of credit in the aggregate amount of
$46.3 million for the benefit of various insurance
companies as collateral for retrospective premiums and retained
losses which could become payable under the terms of the
underlying insurance contracts. These letters of credit expire
annually at various times during the year and are typically
renewed. As of December 31, 2009, no amounts had been drawn
under the letters of credit.
As of December 31, 2009, the Company had commitments to
purchase approximately $186 million of major equipment.
Contingencies
— The Company’s contract
services operations are subject to inherent risks, including
blowouts, cratering, fire and explosions which could result in
personal injury or death, suspended drilling operations, damage
to, or destruction of equipment, damage to producing formations
and pollution or other environmental hazards.
As a protection against these hazards, the Company maintains
general liability insurance coverage of $1.0 million per
occurrence in excess of a $1.0 million self-insured
retention for a total limit of $2.0 million per occurrence,
with $10.0 million of aggregate coverage and excess
liability and umbrella coverages up to $200 million per
occurrence and in the aggregate. The Company maintains a
$1.0 million per occurrence deductible on its workers’
compensation, general liability and automobile liability
insurance coverages. Accrued expenses related to insurance
claims are set forth in Note 6.
The Company believes it is adequately insured for bodily injury
and property damage to others with respect to its operations.
However, such insurance may not be sufficient to protect the
Company against liability for all consequences of personal
injury, well disasters, extensive fire damage, or damage to the
environment. The Company also carries insurance to cover
physical damage to, or loss of, its rigs. However, it does not
cover the full replacement cost of the rigs and the Company does
not carry insurance against loss of earnings resulting from such
damage. There can be no assurance that such insurance coverage
will always be available on terms that are satisfactory to the
Company, if at all.
F-16
Table of Contents
The Company is party to various legal proceedings arising in the
normal course of its business. The Company does not believe that
the outcome of these proceedings, either individually or in the
aggregate, will have a material adverse effect on its financial
condition, results of operations or cash flows.
Other Matters
— The Company has Change in
Control Agreements with its Chairman of the Board, Chief
Executive Officer, two Senior Vice Presidents and its General
Counsel (the “Key Employees”). Each Change in Control
Agreement generally has an initial term with automatic twelve
month renewals unless the Company notifies the Key Employee at
least ninety days before the end of such renewal period that the
term will not be extended. If a change in control of the Company
occurs during the term of the agreement and the Key
Employee’s employment is terminated (i) by the Company
other than for cause or other than automatically as a result of
death, disability or retirement, or (ii) by the Key
Employee for good reason (as those terms are defined in the
Change in Control Agreements), then the Key Employee shall
generally be entitled to, among other things:
| • | a bonus payment equal to the greater of the highest bonus paid after the Change in Control Agreement was entered into and the average of the two annual bonuses earned in the two fiscal years immediately preceding a change in control (such bonus payment prorated for the portion of the fiscal year preceding the termination date); | |
| • | a payment equal to 2.5 times (in the case of the Chairman of the Board and Chief Executive Officer), 2 times (in the case of the Senior Vice Presidents) or 1.5 times (in the case of the General Counsel) of the sum of (i) the highest annual salary in effect for such Key Employee and (ii) the average of the three annual bonuses earned by the Key Employee for the three fiscal years preceding the termination date; and | |
| • | continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board and Chief Executive Officer) or two years (in the case of the Senior Vice Presidents and General Counsel). |
Each Change in Control Agreement provides the Key Employee with
a full
gross-up
payment for any excise taxes imposed on payments and benefits
received under the Change in Control Agreements or otherwise,
including other taxes that may be imposed as a result of the
gross-up
payment.
| 10. | Stockholders’ Equity |
Cash Dividends —
The Company paid cash
dividends during the years ended December 31, 2007, 2008
and 2009 as follows:
| Per Share | Total | |||||||
| (in thousands) | ||||||||
|
2007:
|
||||||||
|
Paid on March 30, 2007
|
$ | 0.08 | $ | 12,527 | ||||
|
Paid on June 29, 2007
|
0.12 | 18,860 | ||||||
|
Paid on September 28, 2007
|
0.12 | 18,690 | ||||||
|
Paid on December 28, 2007
|
0.12 | 18,484 | ||||||
|
Total cash dividends
|
$ | 0.44 | $ | 68,561 | ||||
|
2008:
|
||||||||
|
Paid on March 28, 2008
|
$ | 0.12 | $ | 18,493 | ||||
|
Paid on June 27, 2008
|
0.16 | 25,011 | ||||||
|
Paid on September 29, 2008
|
0.16 | 24,803 | ||||||
|
Paid on December 29, 2008
|
0.16 | 24,558 | ||||||
|
Total cash dividends
|
$ | 0.60 | $ | 92,865 | ||||
F-17
Table of Contents
| Per Share | Total | |||||||
| (in thousands) | ||||||||
|
2009:
|
||||||||
|
Paid on March 31, 2009
|
$ | 0.05 | $ | 7,655 | ||||
|
Paid on June 30, 2009
|
0.05 | 7,675 | ||||||
|
Paid on September 30, 2009
|
0.05 | 7,675 | ||||||
|
Paid on December 30, 2009
|
0.05 | 7,676 | ||||||
|
Total cash dividends
|
$ | 0.20 | $ | 30,681 | ||||
On February 10, 2010, the Company’s Board of Directors
approved a cash dividend on its common stock in the amount of
$0.05 per share to be paid on March 30, 2010 to holders of
record as of March 15, 2010. The amount and timing of all
future dividend payments, if any, is subject to the discretion
of the Board of Directors and will depend upon business
conditions, results of operations, financial condition, terms of
the Company’s credit facilities and other factors.
On August 1, 2007, the Company’s Board of Directors
approved a stock buyback program authorizing purchases of up to
$250 million of the Company’s common stock in open
market or privately negotiated transactions. During the year
ended December 31, 2007, the Company purchased
3,308,850 shares of its common stock under the program at a
cost of approximately $70.4 million. During the year ended
December 31, 2008, the Company purchased
3,502,047 shares of its common stock under the program at a
cost of approximately $66.3 million. During the year ended
December 31, 2009, the Company purchased 5,715 shares
of its common stock under the program at a cost of approximately
$79,000. As of December 31, 2009, the Company is authorized
to purchase approximately $113 million of the
Company’s outstanding common stock under the program.
Shares purchased under the program are accounted for as treasury
stock.
Additionally, the Company purchased 114,983, 152,235 and
20,269 shares of treasury stock from employees during 2009,
2008 and 2007, respectively. These shares were purchased at fair
market value upon the vesting of restricted stock to provide the
employees with the funds necessary to satisfy payroll tax
withholding obligations. The total purchase price for these
shares was approximately $1.5 million, $4.5 million
and $496,000 in 2009, 2008 and 2007, respectively. These
purchases were made pursuant to the terms of the Patterson-UTI
Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to
the stock buyback program.
| 11. | Stock-based Compensation |
The Company uses share-based payments to compensate employees
and non-employee directors. The Company recognizes the cost of
share-based payments under the fair-value-based method. Prior to
2009, share-based awards consisted of equity instruments in the
form of stock options, restricted stock or restricted stock
units, with all such awards subject to service conditions and,
in certain cases, performance conditions. Beginning in 2009,
share-based awards also include cash-settled performance unit
awards which are accounted for as liability awards. The Company
issues shares of common stock when vested stock options are
exercised, when restricted stock is granted and when restricted
stock units vest.
The Company’s shareholders have approved the Patterson-UTI
Energy, Inc. 2005 Long-Term Incentive Plan (the “2005
Plan”), and the Board of Directors adopted a resolution
that no future grants would be made under any of the
Company’s other previously existing plans. During 2008, the
Company amended the 2005 Plan to, among other
F-18
Table of Contents
things, increase the total number of shares authorized for grant
from 6,250,000 to 10,250,000. The Company’s share-based
compensation plans at December 31, 2009 follow:
|
Shares
|
Shares
|
|||||||||||
|
Authorized
|
Awards
|
Available
|
||||||||||
|
Plan Name
|
for Grant | Outstanding | for Grant | |||||||||
|
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as
amended
|
10,250,000 | 4,980,068 | 2,545,524 | |||||||||
|
Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term
Incentive Plan, as amended (“1997 Plan”)
|
— | 2,860,634 | — | |||||||||
|
Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term
Incentive Plan (“2001 Plan”)
|
— | 214,136 | — | |||||||||
|
Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee
Stock Option Plan (“1996 Plan”)
|
— | 35,000 | — | |||||||||
A summary of the 2005 Plan follows:
| • | The Compensation Committee of the Board of Directors administers the plan. | |
| • | All employees including officers and directors are eligible for awards. | |
| • | The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one year for non-employee directors and 3 to 4 years for employees. | |
| • | The Compensation Committee sets the term of awards and no option term can exceed 10 years. | |
| • | All options granted under the plan are granted with an exercise price equal to or greater than the fair market value of the Company’s common stock at the time the option is granted. | |
| • | The plan provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents. As of December 31, 2009, only non-incentive stock options, restricted stock awards, restricted stock units and performance unit awards had been granted under the plan. |
Options granted under the 1997 Plan typically vest over three or
five years as dictated by the Compensation Committee. These
options have terms of no more than ten years. All options were
granted with an exercise price equal to the fair market value of
the related common stock at the time of grant. Restricted stock
awards granted under the 1997 Plan typically vested over four
years.
Options granted under the 2001 Plan typically vest over five
years as dictated by the Compensation Committee. These options
have terms of no more than ten years. All options were granted
with an exercise price equal to the fair market value of the
Company’s common stock at the time of grant.
Options granted under the 1996 Plan typically vest over two or
five years as dictated by the Compensation Committee. These
options have terms of no more than ten years. All options were
granted with an exercise price equal to the fair market value of
the Company’s common stock at the time of grant.
Stock Options —
The Company estimates the grant
date fair values of stock options using the Black-Scholes-Merton
valuation model (“Black-Scholes”). Volatility
assumptions are based on the historic volatility of the
Company’s common stock over the most recent period equal to
the expected term of the options as of the date the options are
granted. The expected term assumptions are based on the
Company’s experience with respect to employee stock option
activity. Dividend yield assumptions are based on the expected
dividends at the time the options are granted. The risk-free
interest rate assumptions are determined by reference to United
States Treasury
F-19
Table of Contents
yields. Weighted-average assumptions used to estimate grant date
fair values for stock options granted in the years ended
December 31, 2009, 2008 and 2007 follow:
| 2009 | 2008 | 2007 | ||||||||||
|
Volatility
|
49.90 | % | 37.04 | % | 36.37 | % | ||||||
|
Expected term (in years)
|
4.00 | 4.17 | 4.00 | |||||||||
|
Dividend yield
|
1.67 | % | 2.27 | % | 1.97 | % | ||||||
|
Risk-free interest rate
|
1.67 | % | 2.91 | % | 4.55 | % | ||||||
Stock option activity for the year ended December 31, 2009
follows:
|
Weighted-average
|
||||||||
| Shares | exercise price | |||||||
|
Outstanding at beginning of year
|
5,933,572 | $ | 21.20 | |||||
|
Granted
|
1,037,500 | $ | 13.12 | |||||
|
Exercised
|
(82,802 | ) | $ | 6.87 | ||||
|
Expired
|
(46,500 | ) | $ | 18.76 | ||||
|
Outstanding at end of year
|
6,841,770 | $ | 20.17 | |||||
|
Exercisable at end of year
|
5,258,103 | $ | 21.18 | |||||
Options outstanding at December 31, 2009 have an aggregate
intrinsic value of approximately $4.7 million and a
weighted-average remaining contractual term of 6.0 years.
Options exercisable at December 31, 2009 have an aggregate
intrinsic value of approximately $1.9 million and a
weighted-average remaining contractual term of 5.1 years.
Additional information with respect to options granted, vested
and exercised during the years ended December 31, 2009,
2008 and 2007 follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Weighted-average grant-date fair value of stock options granted
(per share)
|
$ | 4.71 | $ | 7.20 | $ | 7.09 | ||||||
|
Grant-date fair value of stock options vested during the year
(in thousands)
|
$ | 6,973 | $ | 6,761 | $ | 5,613 | ||||||
|
Aggregate intrinsic value of stock options exercised (in
thousands)
|
$ | 510 | $ | 45,240 | $ | 3,186 | ||||||
As of December 31, 2009, options to purchase
1,583,667 shares were outstanding and not vested. All of
these non-vested options are expected to ultimately vest.
Additional information as of December 31, 2009 with respect
to these non-vested options that are expected to vest follows:
|
Aggregate intrinsic value
|
$2.7 million | |
|
Weighted-average remaining contractual term
|
8.95 years | |
|
Weighted-average remaining expected term
|
3.03 years | |
|
Weighted-average remaining vesting period
|
1.98 years | |
|
Unrecognized compensation cost
|
$7.1 million |
Restricted Stock —
For all restricted stock
awards to date, shares of common stock were issued when the
awards were made. Non-vested shares are subject to forfeiture
for failure to fulfill service conditions and, in certain cases,
performance conditions. Non-forfeitable dividends are paid on
non-vested shares of restricted stock. For restricted stock
awards made prior to 2008, the Company uses the
“graded-vesting” attribution method to recognize
periodic compensation cost over the vesting period. For
restricted stock awards made in 2008 and thereafter, the Company
uses the straight-line method to recognize periodic compensation
cost over the vesting period.
F-20
Table of Contents
Restricted stock activity for the year ended December 31,
2009 follows:
|
Weighted-
|
||||||||
|
average
|
||||||||
|
Grant Date
|
||||||||
| Shares | Fair Value | |||||||
|
Non-vested restricted stock outstanding at beginning of year
|
1,429,571 | $ | 28.49 | |||||
|
Granted
|
603,600 | $ | 13.75 | |||||
|
Vested
|
(745,715 | ) | $ | 27.97 | ||||
|
Forfeited
|
(55,555 | ) | $ | 26.65 | ||||
|
Non-vested restricted stock outstanding at end of year
|
1,231,901 | $ | 21.67 | |||||
As of December 31, 2009, approximately
1,145,000 shares of non-vested restricted stock outstanding
are expected to vest. Additional information as of
December 31, 2009 with respect to these unvested shares
follows:
|
Aggregate intrinsic value
|
$ | 17.6 million | ||
|
Weighted-average remaining vesting period
|
1.54 years | |||
|
Unrecognized compensation cost
|
$ | 13.9 million |
Restricted Stock Units —
For all restricted
stock unit awards made to date, shares of common stock are not
issued until the units vest. Restricted stock units are subject
to forfeiture for failure to fulfill service conditions.
Non-forfeitable cash dividend equivalents are paid on non-vested
restricted stock units.
Restricted stock unit activity for the year ended
December 31, 2009 follows:
|
Weighted
|
||||||||
|
Average
|
||||||||
|
Grant Date
|
||||||||
| Shares | Fair Value | |||||||
|
Non-vested restricted stock units outstanding at beginning of
year
|
17,500 | $ | 31.60 | |||||
|
Granted
|
6,500 | $ | 14.39 | |||||
|
Vested
|
(5,833 | ) | $ | 31.60 | ||||
|
Forfeited
|
(2,000 | ) | $ | 14.39 | ||||
|
Non-vested restricted stock units outstanding at end of year
|
16,167 | $ | 26.81 | |||||
Performance Unit Awards.
On April 28,
2009, the Company granted performance unit awards to certain
executive officers (the “2009 Performance Units”). The
2009 Performance Units provide for those executive officers to
receive a cash payment upon the achievement of certain
performance goals established by the Company during a specified
period. The performance period for the 2009 Performance Units is
the period from April 1, 2009 through March 31, 2012.
The performance goals for the 2009 Performance Units are tied to
the Company’s total shareholder return for the performance
period as compared to total shareholder return for a peer group
determined by the Compensation Committee. These goals are
considered to be market conditions under the relevant accounting
standards. Generally, the recipients will receive a base payment
if the Company’s total shareholder return is positive and,
when compared to the peer group, is at or above the 25th
percentile but less than the 50th percentile; two times the base
if at or above the 50th percentile but less than the 75th
percentile, and four times the base if at the 75th percentile or
higher. The total base amount with respect to the 2009
Performance Units is approximately $1.7 million. As the
2009 Performance Units are to be settled in cash at the end of
the performance period, the Company’s pro-rated obligation
is measured at estimated fair value at the end of each reporting
period and as of December 31, 2009 this pro-rated
obligation was approximately $859,000.
Dividends on Equity Awards —
Non-forfeitable
cash dividends and dividend equivalents paid on equity awards
are recognized as follows:
| • | Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards expected to vest. |
F-21
Table of Contents
| • | Dividends are recognized as additional compensation cost for the portion of restricted stock awards that are not expected to vest or that ultimately do not vest. | |
| • | Dividend equivalents are recognized as additional compensation cost for restricted stock units. |
| 12. | Leases |
The Company incurred rent expense of $11.9 million,
$31.5 million and $27.6 million for the years 2009,
2008 and 2007, respectively. Rent expense is primarily related
to short-term equipment rentals that are passed through to
customers. The Company’s obligations under non-cancelable
operating lease agreements are not material to the
Company’s operations or cash flows.
| 13. | Income Taxes |
Components of the income tax provision applicable to Federal,
state and foreign income taxes for the years ended
December 31, 2009, 2008 and 2007 are as follows (in
thousands):
| 2009 | 2008 | 2007 | ||||||||||
|
Federal income tax expense (benefit):
|
||||||||||||
|
Current
|
$ | (117,493 | ) | $ | 117,367 | $ | 169,634 | |||||
|
Deferred
|
103,574 | 57,879 | 36,911 | |||||||||
| (13,919 | ) | 175,246 | 206,545 | |||||||||
|
State income tax expense (benefit):
|
||||||||||||
|
Current
|
(1,883 | ) | 6,475 | 16,174 | ||||||||
|
Deferred
|
(1,875 | 7,070 | 987 | |||||||||
| (3,758 | ) | 13,545 | 17,161 | |||||||||
|
Foreign income tax expense (benefit):
|
||||||||||||
|
Current
|
338 | 4,256 | 5,220 | |||||||||
|
Deferred
|
(256 | ) | 443 | 424 | ||||||||
| 82 | 4,699 | 5,644 | ||||||||||
|
Total income tax expense (benefit):
|
||||||||||||
|
Current
|
(119,038 | ) | 128,098 | 191,028 | ||||||||
|
Deferred
|
101,443 | 65,392 | 38,322 | |||||||||
|
Total income tax expense (benefit)
|
$ | (17,595 | ) | $ | 193,490 | $ | 229,350 | |||||
The difference between the statutory Federal income tax rate and
the effective income tax rate for the years ended
December 31, 2009, 2008 and 2007 is summarized as follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Statutory tax rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State income taxes
|
4.7 | 1.7 | 1.4 | |||||||||
|
Permanent differences
|
(5.7 | ) | (1.2 | ) | (1.6 | ) | ||||||
|
Other, net
|
0.1 | (0.2 | ) | (0.3 | ) | |||||||
|
Effective tax rate
|
34.1 | % | 35.3 | % | 34.5 | % | ||||||
F-22
Table of Contents
The tax effect of significant temporary differences representing
deferred tax assets and liabilities and changes therein were as
follows (in thousands):
|
December 31,
|
Net
|
December 31,
|
Net
|
December 31,
|
Net
|
December 31,
|
||||||||||||||||||||||
| 2009 | Change | 2008 | Change | 2007 | Change | 2006 | ||||||||||||||||||||||
|
Deferred tax assets:
|
||||||||||||||||||||||||||||
|
Current:
|
||||||||||||||||||||||||||||
|
Net operating loss carryforwards
|
$ | — | $ | — | $ | — | $ | (374 | ) | $ | 374 | $ | (1,496 | ) | $ | 1,870 | ||||||||||||
|
Workers’ compensation allowance
|
24,624 | (1,360 | ) | 25,984 | (602 | ) | 26,586 | 223 | 26,363 | |||||||||||||||||||
|
Embezzlement costs
|
773 | 45 | 728 | 68 | 660 | (13,634 | ) | 14,294 | ||||||||||||||||||||
|
Other
|
18,843 | (2,780 | ) | 21,623 | 3,219 | 18,404 | 3,903 | 14,501 | ||||||||||||||||||||
| 44,240 | (4,095 | ) | 48,335 | 2,311 | 46,024 | (11,004 | ) | 57,028 | ||||||||||||||||||||
|
Non-current:
|
||||||||||||||||||||||||||||
|
Net operating loss carryforwards
|
4,872 | 4,872 | — | — | — | (374 | ) | 374 | ||||||||||||||||||||
|
AMT credit
|
— | — | — | (118 | ) | 118 | — | 118 | ||||||||||||||||||||
|
Expense associated with employee stock options
|
9,129 | 2,500 | 6,629 | 1,381 | 5,248 | 2,186 | 3,062 | |||||||||||||||||||||
|
Federal benefit of foreign deferred tax liabilities
|
9,160 | (256 | ) | 9,416 | 443 | 8,973 | 424 | 8,549 | ||||||||||||||||||||
|
Federal benefit of state deferred tax liabilities
|
9,772 | 2,702 | 7,070 | 1,643 | 5,427 | 735 | 4,692 | |||||||||||||||||||||
|
Other
|
9,485 | 4,120 | 5,365 | 614 | 4,751 | 704 | 4,047 | |||||||||||||||||||||
| 42,418 | 13,938 | 28,480 | 3,963 | 24,517 | 3,675 | 20,842 | ||||||||||||||||||||||
|
Total deferred tax assets
|
86,658 | 9,843 | 76,815 | 6,274 | 70,541 | (7,329 | ) | 77,870 | ||||||||||||||||||||
|
Deferred tax liabilities:
|
||||||||||||||||||||||||||||
|
Current:
|
||||||||||||||||||||||||||||
|
Other
|
(11,363 | ) | 1,044 | (12,407 | ) | (1,753 | ) | (10,654 | ) | (2,493 | ) | (8,161 | ) | |||||||||||||||
|
Non-current:
|
||||||||||||||||||||||||||||
|
Property and equipment basis difference
|
(413,113 | ) | (110,786 | ) | (302,327 | ) | (70,362 | ) | (231,965 | ) | (28,465 | ) | (203,500 | ) | ||||||||||||||
|
Other
|
(10,961 | ) | (7,091 | ) | (3,870 | ) | 8,172 | (12,042 | ) | (6,741 | ) | (5,301 | ) | |||||||||||||||
| (424,074 | ) | (117,877 | ) | (306,197 | ) | (62,190 | ) | (244,007 | ) | (35,206 | ) | (208,801 | ) | |||||||||||||||
|
Total deferred tax liabilities
|
(435,437 | ) | (116,833 | ) | (318,604 | ) | (63,943 | ) | (254,661 | ) | (37,699 | ) | (216,962 | ) | ||||||||||||||
|
Net deferred tax liability
|
$ | (348,779 | ) | $ | (106,990 | ) | $ | (241,789 | ) | $ | (57,669 | ) | $ | (184,120 | ) | $ | (45,028 | ) | $ | (139,092 | ) | |||||||
In assessing the realizability of deferred tax assets,
management considers whether it is more likely than not that
some portion or all of the deferred tax assets will not be
realized. The ultimate realization of deferred tax assets is
dependent upon the generation of future taxable income during
the periods in which those temporary differences become
deductible. Management considers the scheduled reversal of
deferred tax liabilities, projected future taxable income and
tax planning strategies in making this assessment. The Company
expects the deferred tax assets at December 31, 2009 and
2008 to be realized as a result of the reversal of existing
taxable temporary differences giving rise to deferred tax
liabilities and the generation of taxable income; therefore, no
valuation allowance is necessary.
Other deferred tax assets consist primarily of the tax effect of
various allowance accounts and tax-deferred expenses expected to
generate future tax benefit of approximately $28 million.
Other deferred tax liabilities consist
F-23
Table of Contents
primarily of the tax effect of receivables from insurance
companies and tax-deferred income not yet recognized for tax
purposes.
For income tax purposes, the Company generated approximately
$450 million of Federal and state net operating losses
during the year ended December 31, 2009. Of this amount,
approximately $378 million will be carried back to prior
years, and the remaining balance can be carried forward to
future years. The net operating losses that can be carried
forward, if unused, are scheduled to expire as follows:
2014 — $7 million; 2019 —
$15 million and 2029 — $50 million.
The Company adopted a new accounting standard on January 1,
2007 which clarified the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements
and prescribed a recognition threshold and measurement attribute
for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. As a
result of the adoption of this standard in 2007, the Company
reduced a reserve for an uncertain tax position related to a
prior business combination that had originally been recorded as
goodwill (see Note 5). The impact of adjustments to
reserves with respect to other uncertain tax positions was not
material. As of December 31, 2009, the Company had no
unrecognized tax benefits. The Company has established a policy
to account for interest and penalties related to uncertain
income tax positions as operating expenses. As of
December 31, 2009, the tax years ended December 31,
2006 through December 31, 2008 are open for examination by
U.S. taxing authorities. As of December 31, 2009, the
tax years ended December 31, 2005 through December 31,
2008 are open for examination by Canadian taxing authorities.
| 14. | Employee Benefits |
The Company maintains a 401(k) plan for all eligible employees.
The Company’s operating results include expenses of
approximately $2.8 million in 2009, $4.5 million in
2008 and $4.0 million in 2007 for the Company’s cash
contributions to the plan.
| 15. | Business Segments |
The Company’s revenues, operating profits and identifiable
assets are primarily attributable to three business segments:
(i) contract drilling of oil and natural gas wells,
(ii) pressure pumping services and (iii) the
investment, on a working interest basis, in oil and natural gas
properties. Each of these segments represents a distinct type of
business. These segments have separate management teams which
report to the Company’s chief operating decision maker. The
results of operations in these segments are regularly reviewed
by the chief operating decision maker for purposes of
determining resource allocation and assessing performance. As
discussed in Note 2, the Company exited the drilling and
completion fluids services business which previously was
reported as a business segment in January 2010. Operating
results for that business for the years ended December 31,
2009, 2008 and 2007 are presented as discontinued operations in
the consolidated statements of operations.
Contract Drilling
— The Company markets its
contract drilling services to major and independent oil and
natural gas operators. As of December 31, 2009, the Company
had 341 marketable land-based drilling rigs, of which 73 of the
drilling rigs were based in west Texas and southeastern New
Mexico; 100 in north central and east Texas, northern Louisiana
and Mississippi; 56 in the Rocky Mountain region (Colorado,
Utah, Wyoming, Montana and North Dakota); 49 in south Texas; 28
in the Texas panhandle, Oklahoma and Arkansas; 20 in western
Canada; and 15 in the Appalachian Basin.
For the years ended December 31, 2009, 2008 and 2007,
contract drilling revenue earned in Canada was
$45.4 million, $88.5 million and $72.9 million,
respectively. Additionally, we had long-lived assets within our
contract drilling segment located in Canada of
$69.2 million and $67.2 million as of
December 31, 2009 and 2008, respectively.
Pressure Pumping
— The Company provides
pressure pumping services primarily in the Appalachian Basin.
Pressure pumping services consist primarily of well stimulation
and cementing for the completion of new wells and remedial work
on existing wells. Well stimulation involves processes inside a
well designed to enhance the flow of oil, natural gas, or other
desired substances from the well. Cementing is the process of
inserting material between the hole and the pipe to center and
stabilize the pipe in the hole.
F-24
Table of Contents
Oil and Natural Gas
— The Company has been
engaged in the development, exploration, acquisition and
production of oil and natural gas. Through October 31,
2007, the Company served as operator with respect to several
properties and was actively involved in the development,
exploration, acquisition and production of oil and natural gas.
Effective November 1, 2007 the Company sold the related
operations portion of its exploration and production business.
The Company continues to own and invest in oil and natural gas
assets as a working interest owner. The Company’s oil and
natural gas interests are located primarily in Texas and New
Mexico.
The following tables summarize selected financial information
relating to the Company’s business segments (in thousands):
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Revenues:
|
||||||||||||
|
Contract drilling
|
$ | 600,423 | $ | 1,808,600 | $ | 1,744,884 | ||||||
|
Pressure pumping
|
161,441 | 217,494 | 202,812 | |||||||||
|
Oil and natural gas
|
21,218 | 42,360 | 41,637 | |||||||||
|
Total segment revenues
|
783,082 | 2,068,454 | 1,989,333 | |||||||||
|
Elimination of intercompany revenues(a)
|
(1,136 | ) | (4,574 | ) | (3,237 | ) | ||||||
|
Total revenues
|
$ | 781,946 | $ | 2,063,880 | $ | 1,986,096 | ||||||
|
Income (loss) from continuing operations before income taxes:
|
||||||||||||
|
Contract drilling
|
$ | (11,219 | ) | $ | 520,636 | $ | 558,792 | |||||
|
Pressure pumping
|
1,017 | 42,019 | 64,257 | |||||||||
|
Oil and natural gas
|
950 | 13,711 | 10,998 | |||||||||
| (9,252 | ) | 576,366 | 634,047 | |||||||||
|
Corporate and other
|
(35,577 | ) | (34,596 | ) | (31,124 | ) | ||||||
|
Embezzlement recoveries(b)
|
— | — | 43,955 | |||||||||
|
Net (loss) gain on asset disposals(c)
|
(3,385 | ) | 4,163 | 16,432 | ||||||||
|
Interest income
|
381 | 1,553 | 2,351 | |||||||||
|
Interest expense
|
(4,148 | ) | (630 | ) | (2,187 | ) | ||||||
|
Other
|
426 | 502 | 363 | |||||||||
|
Income (loss) from continuing operations before income taxes
|
$ | (51,555 | ) | $ | 547,358 | $ | 663,837 | |||||
|
Identifiable assets:
|
||||||||||||
|
Contract drilling
|
$ | 2,129,567 | $ | 2,255,421 | $ | 2,132,910 | ||||||
|
Pressure pumping
|
213,094 | 210,805 | 154,120 | |||||||||
|
Oil and natural gas
|
25,355 | 31,760 | 37,885 | |||||||||
|
Corporate and other(d)
|
294,136 | 214,831 | 140,284 | |||||||||
|
Total assets
|
$ | 2,662,152 | $ | 2,712,817 | $ | 2,465,199 | ||||||
|
Depreciation, depletion and impairment:
|
||||||||||||
|
Contract drilling
|
$ | 248,424 | $ | 239,700 | $ | 213,812 | ||||||
|
Pressure pumping
|
27,589 | 19,600 | 14,311 | |||||||||
|
Oil and natural gas
|
12,927 | 15,856 | 17,410 | |||||||||
|
Corporate and other
|
907 | 834 | 813 | |||||||||
|
Total depreciation, depletion and impairment
|
$ | 289,847 | $ | 275,990 | $ | 246,346 | ||||||
F-25
Table of Contents
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Capital expenditures:
|
||||||||||||
|
Contract drilling
|
$ | 395,376 | $ | 360,645 | $ | 539,506 | ||||||
|
Pressure pumping
|
43,144 | 61,289 | 47,582 | |||||||||
|
Oil and natural gas
|
7,341 | 22,981 | 17,516 | |||||||||
|
Corporate and other
|
6,785 | 511 | — | |||||||||
|
Total capital expenditures
|
$ | 452,646 | $ | 445,426 | $ | 604,604 | ||||||
| (a) | Includes contract drilling intercompany revenues related to drilling services provided for wells in which the Company owns a working interest. | |
| (b) | The Company’s former CFO has pleaded guilty to criminal charges and has been sentenced and is serving a term of imprisonment arising out of his embezzlement of funds from the Company prior to his termination in 2005. The net embezzlement recovery in 2007 includes the recognition of the recovery of assets seized by a court appointed receiver, net of related professional fees. | |
| (c) | Net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments. | |
| (d) | Corporate and other assets primarily include identifiable assets associated with the Company’s former drilling and completion fluids segment as well as cash on hand managed by the parent corporation and certain deferred Federal income tax assets. |
| 16. | Concentrations of Credit Risk |
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist primarily of demand
deposits, temporary cash investments and trade receivables.
The Company believes it has placed its demand deposits and
temporary cash investments with high credit-quality financial
institutions. At December 31, 2009 and 2008, the
Company’s demand deposits and temporary cash investments
consisted of the following (in thousands):
| 2009 | 2008 | |||||||
|
Deposits in FDIC and SIPC-insured institutions under insurance
limits
|
$ | 20,543 | $ | 588 | ||||
|
Deposits in FDIC and SIPC-insured institutions over insurance
limits
|
47,376 | 79,387 | ||||||
|
Deposits in foreign banks
|
4,383 | 18,805 | ||||||
| 72,302 | 98,780 | |||||||
|
Less outstanding checks and other reconciling items
|
(22,425 | ) | (17,557 | ) | ||||
|
Cash and cash equivalents
|
$ | 49,877 | $ | 81,223 | ||||
Concentrations of credit risk with respect to trade receivables
are primarily focused on companies involved in the exploration
and development of oil and natural gas properties. The
concentration is somewhat mitigated by the diversification of
customers for which the Company provides services. As is general
industry practice, the Company typically does not require
customers to provide collateral. No significant losses from
individual customers were experienced during the years ended
December 31, 2009, 2008, or 2007. The Company recognized
bad debt expense for 2009, 2008 and 2007 of $3.8 million,
$4.4 million and $2.9 million, respectively.
The carrying values of cash and cash equivalents, trade
receivables and accounts payable approximate fair value due to
the short-term maturity of these items.
F-26
Table of Contents
| 17. | Related Party Transactions |
Joint Operation of Oil and Natural Gas
Properties
— Through October 31, 2007, the
Company served as operator with respect to several properties
and was actively involved in the development, exploration,
acquisition and production of oil and natural gas. Effective
November 1, 2007, the Company sold the operations portion
of its exploration and production business. The Company
continues to own and invest in oil and natural gas assets as a
working interest owner. During the time that the Company served
as operator, it served as operator with respect to certain oil
and natural gas properties in which certain of its affiliated
persons have participated, either individually or through
entities they control. These participations were typically
through working interests in prospects or properties originated
or acquired by Patterson Petroleum LLC, a wholly owned
subsidiary of Patterson-UTI Energy, Inc.
During the time that the Company served as operator, sales of
working interests to affiliated parties were made by the Company
at its cost, comprised of the Company’s costs of acquiring
and preparing the working interests for sale plus a promote fee
in some cases. These costs were paid by the working interest
owners on a pro rata basis based upon their working interest
ownership percentage. The price at which working interests were
sold to affiliated persons was the same price at which working
interests were sold to unaffiliated persons except that in some
cases the affiliated persons also paid a promote fee. The
affiliated persons received oil and natural gas production
revenue (net of royalty) of $19.0 million from these
properties in 2007. These persons or entities in turn paid for
joint operating costs (including drilling and other development
expenses) of $9.2 million incurred in 2007.
| 18. | Quarterly Financial Information (in thousands, except per share amounts) (unaudited) |
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||
|
2008
|
||||||||||||||||
|
Operating revenues
|
$ | 472,004 | $ | 487,538 | $ | 572,798 | $ | 531,540 | ||||||||
|
Operating income
|
119,191 | 122,364 | 166,126 | 138,252 | ||||||||||||
|
Income from continuing operations, net of income taxes
|
76,354 | 75,184 | 110,047 | 92,282 | ||||||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
1,055 | 6,238 | (1,301 | ) | (12,790 | ) | ||||||||||
|
Net income
|
77,409 | 81,422 | 108,746 | 79,492 | ||||||||||||
|
Basic income (loss) per common share:
|
||||||||||||||||
|
From continuing operations
|
$ | 0.50 | $ | 0.48 | $ | 0.71 | $ | 0.60 | ||||||||
|
From discontinued operations
|
$ | 0.01 | $ | 0.04 | $ | (0.01 | ) | $ | (0.08 | ) | ||||||
|
Net income
|
$ | 0.51 | $ | 0.52 | $ | 0.70 | $ | 0.52 | ||||||||
|
Diluted income (loss) per common share:
|
||||||||||||||||
|
From continuing operations
|
$ | 0.49 | $ | 0.48 | $ | 0.70 | $ | 0.60 | ||||||||
|
From discontinued operations
|
$ | 0.01 | $ | 0.04 | $ | (0.01 | ) | $ | (0.08 | ) | ||||||
|
Net income
|
$ | 0.50 | $ | 0.52 | $ | 0.69 | $ | 0.52 | ||||||||
F-27
Table of Contents
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||
|
2009
|
||||||||||||||||
|
Operating revenues
|
$ | 268,209 | $ | 140,497 | $ | 159,671 | $ | 213,569 | ||||||||
|
Operating income (loss)
|
25,154 | (25,855 | ) | (24,619 | ) | (22,894 | ) | |||||||||
|
Income (loss) from continuing operations, net of income taxes
|
15,835 | (16,891 | ) | (16,814 | ) | (16,090 | ) | |||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
368 | (852 | ) | (1,766 | ) | (2,080 | ) | |||||||||
|
Net income (loss)
|
16,203 | (17,743 | ) | (18,580 | ) | (18,170 | ) | |||||||||
|
Basic income (loss) per common share:
|
||||||||||||||||
|
From continuing operations
|
$ | 0.10 | $ | (0.11 | ) | $ | (0.11 | ) | $ | (0.11 | ) | |||||
|
From discontinued operations
|
$ | 0.00 | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
|
Net income (loss)
|
$ | 0.10 | $ | (0.12 | ) | $ | (0.12 | ) | $ | (0.12 | ) | |||||
|
Diluted income (loss) per common share:
|
||||||||||||||||
|
From continuing operations
|
$ | 0.10 | $ | (0.11 | ) | $ | (0.11 | ) | $ | (0.11 | ) | |||||
|
From discontinued operations
|
$ | 0.00 | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
|
Net income (loss)
|
$ | 0.10 | $ | (0.12 | ) | $ | (0.12 | ) | $ | (0.12 | ) | |||||
As discussed in Note 2, the Company exited the drilling and
completion fluids services business in January 2010. The results
of operations related to the drilling and completion fluids
operating segment have been reclassified and presented as
discontinued operations in the quarterly financial information
above.
F-28
Table of Contents
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
|
Charged to
|
||||||||||||||||
|
Beginning
|
Costs and
|
Ending
|
||||||||||||||
|
Description
|
Balance | Expenses | Deductions(1) | Balance | ||||||||||||
| (In thousands) | ||||||||||||||||
|
Year Ended December 31, 2009
|
||||||||||||||||
|
Deducted from asset accounts:
|
||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 9,330 | $ | 4,700 | $ | 3,119 | $ | 10,911 | ||||||||
|
Year Ended December 31, 2008
|
||||||||||||||||
|
Deducted from asset accounts:
|
||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 10,014 | $ | 4,350 | $ | 5,034 | $ | 9,330 | ||||||||
|
Year Ended December 31, 2007
|
||||||||||||||||
|
Deducted from asset accounts:
|
||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 7,484 | $ | 2,550 | $ | 20 | $ | 10,014 | ||||||||
| (1) | Uncollectible accounts written off net of recoveries. |
S-1
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has
duly caused this Report on
Form 10-K
to be signed on its behalf by the undersigned, thereunto duly
authorized.
PATTERSON-UTI ENERGY, INC.
|
By:
/s/ Douglas
J. Wall
|
Douglas J. Wall
President and Chief Executive Officer
Date: February 19, 2010
Pursuant to the requirements of the Securities Exchange Act of
1934, this Report on
Form 10-K
has been signed by the following persons on behalf of
Patterson-UTI Energy, Inc. and in the capacities indicated as of
February 19, 2010.
|
Signature
|
Title
|
|||
|
/s/ Mark
S. Siegel
|
Chairman of the Board | |||
|
/s/ Douglas
J. Wall
(Principal Executive Officer) |
President and Chief Executive Officer | |||
|
/s/ John
E. Vollmer III
(Principal Financial Officer) |
Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer | |||
|
/s/ Gregory
W. Pipkin
(Principal Accounting Officer) |
Chief Accounting Officer and Assistant Secretary | |||
|
/s/ Kenneth
N. Berns
|
Senior Vice President and Director | |||
|
/s/ Charles
O. Buckner
|
Director | |||
|
/s/ Curtis
W. Huff
|
Director | |||
|
/s/ Terry
H. Hunt
|
Director | |||
|
/s/ Kenneth
R. Peak
|
Director | |||
|
/s/ Cloyce
A. Talbott
|
Director | |||
Table of Contents
EXHIBIT INDEX
| 3 | .1 | Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference). | ||
| 3 | .2 | Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference). | ||
| 3 | .3 | Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference). | ||
| 4 | .1 | Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (filed January 14, 1997 as Exhibit 2 to the Company’s Registration Statement on Form 8-A and incorporated herein by reference). | ||
| 4 | .2 | Amendment to Rights Agreement dated as of October 23, 2001 (filed October 31, 2001 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001 and incorporated herein by reference). | ||
| 4 | .3 | Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2). | ||
| 4 | .4 | Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned by REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). | ||
| 10 | .1 | For additional material contracts, see Exhibits 4.1, 4.2 and 4.4. | ||
| 10 | .2 | Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).* | ||
| 10 | .3 | Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).* | ||
| 10 | .4 | Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).* | ||
| 10 | .5 | Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).* | ||
| 10 | .6 | Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by reference).* | ||
| 10 | .7 | First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). | ||
| 10 | .8 | Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference). | ||
| 10 | .9 | Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time.* | ||
| 10 | .10 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .11 | Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed on September 24, 2007 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by reference).* | ||
| 10 | .12 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* |
Table of Contents
| 10 | .13 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .14 | Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III (filed on February 25, 2005 as Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).* | ||
| 10 | .15 | Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler and Gregory W. Pipkin (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).* | ||
| 10 | .16 | Severance Agreement between Patterson-UTI Energy, Inc. and Douglas J. Wall, effective as of August 31, 2007 (filed September 4, 2007 as Exhibit 10.3 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* | ||
| 10 | .17 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of August 31, 2007, by and between Patterson-UTI Energy, Inc. and Douglas J. Wall (filed September 4, 2007 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* | ||
| 10 | .18 | Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* | ||
| 10 | .19 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .20 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .21 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .22 | First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* | ||
| 10 | .23 | Credit Agreement dated March 20, 2009, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC Bank USA, N.A., as lender, Bank of America, N.A., as syndication agent, letter of credit issuer and lender, and The Bank of Tokyo-Mitsubishi UFJ, Ltd. as documentation agent and lender (filed March 25, 2009 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). | ||
| 10 | .24 | Commitment Increase and Joinder Agreement dated June 19, 2009, among the Company, as borrower, Regions Bank as the new lender, Bank of America, N.A. as a letter of credit issuer and Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender (filed August 4, 2009 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference). | ||
| 10 | .25 | Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form 10-K, as amended, and incorporated herein by reference).* | ||
| 21 | .1 | Subsidiaries of the Registrant. | ||
| 23 | .1 | Consent of Independent Registered Public Accounting Firm. | ||
| 31 | .1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. |
Table of Contents
| 31 | .2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. | ||
| 32 | .1 | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 101 | The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, (v) Notes to Consolidated Financial Statements, tagged as blocks of text, and (vi) Valuation and Qualifying Accounts. |
| * | Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. |
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Submission Of Matters To A Vote Of Security HoldersPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder 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 DataItem 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 Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial Statement Schedule