P a t t e r s o n - U t I e n e r g y , I n c . 2 0 1 0 a n n U a l r e P o r t
Patterson-UTI Energy, Inc.
450 Gears Road, Suite 500
Houston, Texas 77067
Telephone: (281) 765-7100
Fax: (281) 765-7175
www.patenergy.com
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p a T T e r S o n - U T i e n e r G y , i n C . 2 0 1 0 a n n u a l r e p o r t
c o r p o r a t e i n f o r m a t i o n
corporate officers
corporate office
transfer agent
Chairman, Patterson-UTI Energy, Inc.;
Chairman
mark S. Siegel
Patterson-UTI Energy, Inc.
450 Gears Road, Suite 500
Houston, Texas 77067
Continental Stock
Transfer & Trust Company
17 Battery Place, 8th Floor
Telephone: (281) 765-7100
New York, NY 10004
Fax: (281) 765-7175
www.patenergy.com
Telephone: (212) 509-4000
www.continentalstock.com
common stock
inDepenDent auDitor
Nasdaq: PTEN
PricewaterhouseCoopers LLP
Directors
mark S. Siegel
President, Remy Investors and
Consultants, Incorporated
Kenneth n. Berns
Senior Vice President,
Patterson-UTI Energy, Inc.
Charles o. Buckner
Retired Partner,
Ernst & Young LLP
Curtis W. Huff
Managing Partner
Intervale Capital LLC
Terry H. Hunt
Energy Consultant
Kenneth r. peak
President and
Chief Executive Officer,
Contango Oil & Gas
Cloyce a. Talbott
Former President and
Chief Executive Officer,
Patterson-UTI Energy, Inc.
Douglas J. Wall
President and
Chief Executive Officer
Kenneth n. Berns
Senior Vice President
John e. Vollmer iii
Senior Vice President –
Corporate Development,
Chief Financial Officer
and Treasurer
Seth D. Wexler
General Counsel
and Secretary
Gregory W. pipkin
Chief Accounting Officer
and Assistant Secretary
Company profile Patterson-UTI Energy, Inc. subsidiaries provide onshore
contract drilling and pressure pumping services to exploration and production
companies in North America. Patterson-UTI Drilling Company LLC has
approximately 350 marketable land-based drilling rigs that operate primarily
in the oil and natural gas producing regions of Texas, New Mexico, Oklahoma,
Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North
Dakota, Pennsylvania, West Virginia and western Canada. Universal Pressure
Pumping, Inc. and Universal Well Services, Inc. provide pressure pumping
services primarily in Texas and the Appalachian Basin.
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P a t t e r s o n - UtI en e r g y , I nC.
2 0 1 0 A n n u Al R e pO Rt
Financial Highlights
(in thousands, except per share amounts – unaudited)
2006
2007
Year Ended December 31,
2008
2009
2010
Revenues
Operating income (loss)
Net income (loss)
Net income (loss) per share
Basic
Diluted
Cash dividends per share
Total assets
Borrowings under revolving credit facility
Long-term debt
Stockholders’ equity
Working capital
Operational Highlights
(dollars in thousands – unaudited)
Contract Drilling:
Revenues
Average revenue per day
Average direct operating costs per day
Average margin per day (1)
Operating days
Average rigs operating during the year
Number of rigs operated during the year
Number of wells drilled during the year
Pressure Pumping:
Revenues
Average revenue per fracturing job
Average revenue per other job
Average revenue per total job
Average direct operating costs per total job
Average margin per total job (1)
Number of fracturing jobs
Number of other jobs
Total number of jobs
Quintiplex fracturing horsepower at end of year
Triplex fracturing horsepower at end of year
Other pumping equipment horsepower at end of year
Total hydraulic horsepower at end of year
$ 2,354,228
1,010,319
673,254
4.05
4.00
0.28
2,192,503
120,000
—
1,562,466
334,429
$ 2,169,370
20.05
$
9.26
$
$
10.79
108,192
296
331
5,050
$ 145,671
33.19
$
6.61
$
13.51
$
7.93
$
5.58
$
2,797
7,986
10,783
—
43,200
22,200
65,400
$ 1,986,096
663,310
438,639
2.81
2.78
0.44
2,465,199
50,000
—
1,896,030
226,209
$ 1,741,647
19.55
$
10.81
$
8.74
$
89,095
244
338
4,237
$ 202,812
40.62
$
7.16
$
15.56
$
9.00
$
6.57
$
3,274
9,757
13,031
—
67,200
28,200
95,400
$ 2,063,880
545,933
347,069
2.25
2.23
0.60
2,712,817
—
—
2,126,942
337,615
$ 1,804,026
19.38
$
11.16
$
8.22
$
93,068
254
315
4,218
$ 217,494
49.62
$
$
8.04
18.03
$
12.22
$
5.81
$
2,898
9,162
12,060
11,250
79,200
32,400
122,850
$ 781,946
(48,214)
(38,290)
(0.25)
(0.25)
0.20
2,662,152
—
—
2,081,700
263,511
$ 599,287
17.95
$
10.71
$
7.24
$
33,394
91
243
1,539
$ 161,441
70.88
$
9.17
$
23.14
$
17.78
$
5.35
$
1,579
5,399
6,978
45,000
82,800
35,400
163,200
$ 1,462,931
200,925
116,942
0.76
0.76
0.20
3,423,031
—
392,500
2,187,607
241,445
$ 1,081,898
17.67
$
10.71
$
6.96
$
61,244
168
220
2,919
$ 350,608
$ 180.21
12.47
$
46.29
$
31.04
$
15.25
$
1,527
6,047
7,574
226,750
126,850
81,600
435,200
(1) Average margin represents average revenue minus average direct operating costs and excludes provisions for bad debts, other charges, depreciation, amortization and
impairment and selling, general and administrative expenses.
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C o n t r a Ct D r i l l i n g
We have made significant upgrades over the last several years
to our drilling fleet to match the needs of our customers.
While conventional wells remain an important source of natural gas
and oil, our customers have expanded the development of shale and
other unconventional wells to help supply the long-term demand
for natural gas and oil in North America.
To address our customers’ needs for drilling wells in the
newer horizontal shale and other unconventional “resource
plays”, we have expanded our areas of operations and improved
the capability of our drilling fleet. We have continued to deliver
new APEX™ rigs to the market and make performance and
safety improvements to existing high-capacity rigs. In 2010, we
added 19 new APEX™ rigs to our fleet consisting of nine APEX™ 1500, five APEX™ 1000 and five APEX™
Walking rigs. In addition, we plan to complete 25 new APEX™ rigs in 2011.
APEX™ 1500s are 1,500HP electric rigs with advanced EDS systems, 500 ton top drives, iron roughnecks,
hydraulic catwalks, and other highly automated pipe handling equipment. APEX™ 1000s are 1,000HP electric
rigs with advanced technology equipment similar to the APEX™ 1500s, but with a more compact design to fit
on smaller locations, such as for drilling Marcellus Shale wells in Appalachia. APEX™ Walking rigs are designed
to efficiently drill multiple wells from a single pad, by “walking” between the wellbores without requiring time
to lower the mast and remove the drill pipe.
Additionally, to meet the needs of the increased demand for drilling horizontal wells, we have continued to
acquire top drives and improve the capability of many of our non-APEX™ rigs to efficiently drill these wells.
We are a major participant in significant unconventional “resource plays” in the United States.
We also remain a market leader in the drilling of conventional wells of varying depths. Over the last several years
we have made substantial improvements to our overall drilling fleet to improve the drilling efficiency of these wells.
Improvements have included higher capacity pumps, high-efficiency mud systems and iron roughnecks.
As of the end of 2010, we had 356 marketable land drilling rigs of which 80% had depth capacities ranging
from 12,000 to 30,000 feet.
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P a t t e r s o n - UtI en e r g y , I n c.
2 0 1 0 A n nU Al reP Or t
P r eS S Ur e PUmP In g
Our pressure pumping businesses, Universal Pressure
Pumping, Inc. and Universal Well Services, Inc., are
adding capacity as a result of increased demand for
our services as customers expand development of
shale, liquids-rich and oil reserves. The primary source
of revenues for this business segment is fracturing services.
Other services provided include cementing, acidizing,
nitrogen vaporization and flowback testing.
Our coverage of shale basins includes the Marcellus in
the Appalachian region, the Eagle Ford in South Texas
and the Barnett in North Texas. Our pressure pumping
operations also extend to the oily Permian basin in West
Texas and New Mexico. These businesses have a long-standing presence in most of these areas, which gives
us a home field advantage as development increases.
Our total hydraulic pumping horsepower has increased more than 550% over the past four years to
approximately 435,000 as of December 31, 2010. This growth was accomplished through the purchase of
new-build equipment and through the acquisition, during the fourth quarter of 2010, of the assets which are
operated by Universal Pressure Pumping, Inc. New-build additions included quintiplex frac pumpers, 140
BPM blenders, and satellite equipped frac vans which allow efficient completion of complex shale frac jobs.
Also, we plan to add approximately 200,000 hydraulic horsepower of pumping capacity in 2011.
As the country continues to recognize and develop the huge energy resources available on land in the U.S.,
we expect the pressure pumping industry will continue its growth. We have a strong and deep foundation
from which to grow each part of our services and take full advantage of the many opportunities that are
presented to us.
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P a t t e r s o n - UtI en e r g y , I n c.
2 0 1 0 A n n u Al R e p oRt
Financial Review
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
¥
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
n
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
or
Patterson-UTI Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
450 Gears Road, Suite 500, Houston, Texas
(Address of principal executive offices)
75-2504748
(I.R.S. Employer
Identification No.)
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
Common Stock, $0.01 Par Value
Preferred Share Purchase Rights
Name of Exchange on Which Registered
The Nasdaq Global Select Market
The Nasdaq Global Select Market
Securities Registered Pursuant to Section 12(g) of the Act:
None
or No n
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¥
or No ¥
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 n
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 ¥
No n
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 ¥
or No n
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. ¥
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act. (Check one):
Large accelerated filer ¥
Accelerated filer n
Non-accelerated filer n
Smaller reporting company n
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes n
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010, the
last business day of the registrant’s most recently completed second fiscal quarter, was $1,948,746,558, calculated by reference to the closing
price of $12.87 for the common stock on the Nasdaq Global Select Market on that date.
No ¥
As of February 11, 2011, the registrant had outstanding 154,203,597 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 2011 Annual Meeting of Stockholders are incorporated by reference into
Part III of this report.
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 building new equipment and
additional 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 and 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 rates, utilization, margins and planned capital expenditures,
excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or
construction, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating
acquisitions, shortages of equipment and materials, 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.
PART I
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
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, 2010, we had a drilling fleet that consisted of 356 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 Texas and the Appalachian
Basin. Pressure pumping 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 working 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 sold
our drilling and completion fluids services business on January 20, 2010.
On October 1, 2010 we acquired the assets and operations of a pressure pumping business and an electric
wireline business. The electric wireline business that we acquired was classified as held for sale at December 31,
2010 and sold on January 27, 2011. The results of our drilling and completion fluids services business and our
electric wireline business are presented as discontinued operations in this Report.
Industry Segments
Our revenues, operating profits and identifiable assets are primarily attributable to three industry segments:
(cid:129) contract drilling services,
(cid:129) pressure pumping services, and
(cid:129) oil and natural gas exploration and production.
All of our industry segments had operating profits in 2010 and 2008. 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, 2010, we had 356 marketable land-based drilling rigs based in the following regions:
(cid:129) 73 in west Texas and southeastern New Mexico,
(cid:129) 97 in north central and east Texas, northern Louisiana and Mississippi,
(cid:129) 58 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana and North Dakota),
(cid:129) 51 in south Texas and southern Louisiana,
(cid:129) 32 in the Texas panhandle, Oklahoma and Arkansas,
(cid:129) 25 in the Appalachian Basin, and
(cid:129) 20 in western Canada.
2
Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,000 feet to 25,000 feet. Of
these drilling rigs, 124 are electric rigs and 232 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 $1.4 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 2010, 2009 and 2008, we spent approximately $656 million, $395 million and $361 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 2010, our average number of days to drill a well (which includes moving to the drill site,
rigging up and rigging down) was approximately 21 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. 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 2010, 2009 and 2008 were under daywork contracts.
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-upon
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
3
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 2010 or 2008.
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- upon 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
2010
168
Average rigs operating per day(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
220
Number of rigs operated during the year . . . . . . . . . . . . . . . . . . . . . . .
Number of wells drilled during the year . . . . . . . . . . . . . . . . . . . . . . . .
2,919
Number of operating days(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61,244
91
243
1,539
33,394
254
315
4,218
93,068
(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 zero in 2010, 2,070 in 2009 and 486 in 2008.
Drilling Rigs and Related Equipment — We estimate the depth capacity with respect to our marketable rigs as
of December 31, 2010 to be as follows:
Depth Rating (Ft.)
Number of Rigs
Canada
Total
U.S.
5,000 to 7,999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —
59
8,000 to 11,999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
193
12,000 to 15,999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
84
16,000 to 25,000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Totals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
336
3
9
8
—
20
3
68
201
84
356
At December 31, 2010, we owned and operated 317 trucks and 402 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.
Pressure Pumping Operations
General — We provide pressure pumping services to oil and natural gas operators primarily in Texas and the
Appalachian Basin. Pressure pumping services consist of well stimulation and cementing for the completion of new
wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require
4
well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids
under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well
stimulation services. The cementing process inserts material between the wall of the well bore and the casing to
support and stabilize the casing.
Equipment — Our pressure pumping equipment at December 31, 2010 includes equipment used in providing
hydraulic and nitrogen fracturing services as well as nitrogen, cementing and acid pumping services as follows:
Number of Units . . . . . . . . . . . . . . . . . . . . . . . . . .
Approximate Hydraulic Horsepower . . . . . . . . . . . .
101
226,750
90
126,850
130
81,600
Quintiplex
Fracturing
Equipment
Triplex
Fracturing
Equipment
Other
Pumping
Equipment
Total
321
435,200
Our pressure pumping operations are supported by a fleet of equipment including blenders, tractors, manifold
trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of
materials at the worksite.
Oil and Natural Gas Interests
We own and invest in oil and natural gas assets as a working interest owner. Our oil and natural gas working
interests are located primarily in producing regions of Texas and New Mexico.
Customers
The customers of each of our contract drilling and pressure pumping business segments are oil and natural gas
operators. Our customer base includes both major and independent oil and natural gas operators. During 2010, 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 equip-
ment 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 highly 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:
(cid:129) drilling of oil and natural gas wells,
(cid:129) the relationships with our employees,
(cid:129) containment and disposal of hazardous materials, oilfield waste, other waste materials and acids,
(cid:129) use of underground storage tanks,
(cid:129) use of underground injection wells, and
(cid:129) hydraulic fracturing and related activities.
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
facilities or extraordinary expenditures to comply with
capital expenditures for environmental control
5
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, and otherwise 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. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a Federal,
state, foreign or local governmental authority, could have a material adverse effect on our business, financial
condition and results of operation.
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.
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:
(cid:129) owners and operators of sites, and
(cid:129) 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:
(cid:129) the prevention of discharges, including oil and produced water spills, and
(cid:129) 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. 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
6
under the Federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much
greater and can include natural resource damages.
Our activities include the performance of hydraulic fracturing services to enhance the production of oil and
natural gas from formations with low permeability, such as shales. Due to concerns raised relating to potential
impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the Federal level and in
some states have been initiated to render permitting and compliance requirements more stringent for hydraulic
fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas
production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render
for our exploration and production customers.
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 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:
(cid:129) accidents at the work location,
(cid:129) blow-outs,
(cid:129) cratering,
(cid:129) fires, and
(cid:129) explosions.
These and other hazards could cause:
(cid:129) personal injury or death,
(cid:129) suspension of drilling operations, or
(cid:129) 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, including through:
(cid:129) oil or produced water spillage,
(cid:129) natural gas leaks, and
(cid:129) fires.
7
We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we
are not fully insured against all risks, either because insurance is not available or because of the high premium costs.
Such risks include personal injury, well disasters, extensive fire damage, damage to the environment, and other
hazards. The insurance coverage that we maintain includes 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 cannot assure, however, that any insurance obtained by us will be
adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms
that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and other
assets, such insurance does not cover the full replacement cost of the rigs or other assets, and we do not carry
insurance against loss of earnings resulting from such damage. Liabilities for which we are not insured, or which
exceed the policy limits of our applicable insurance, could have a material adverse effect on our financial condition
and results of operations.
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. There is no assurance that we will obtain such contractual indemnity, and if
obtained, whether such indemnity will be enforceable, whether the customer will be able to satisfy such indemnity
or whether such indemnity will be supported by adequate insurance maintained by the customer.
Employees
We had approximately 7,000 full-time employees at December 31, 2010. 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 annual Spring thaw.
Raw Materials and Subcontractors
We use many suppliers of raw materials and services. Although, these materials and services have historically
been available, 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.
Beginning in late 2008 and continuing through 2009, there was a substantial deterioration in the global
economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and
access to financing was 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 resulted in certain of
our customers experiencing an inability to pay suppliers, including us. Although the significant deterioration in the
global economic environment appeared to stabilize to some degree during 2010, there is no assurance that the global
economic environment could not quickly deteriorate again due to one or more factors. A return of the conditions
causing a deterioration in the global economic environment could have a material adverse effect on our business,
financial condition, cash flows and results of operations.
8
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 and cash flows are highly dependent upon prevailing prices for natural gas and oil.
For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by:
(cid:129) market supply and demand,
(cid:129) international military, political and economic conditions, and
(cid:129) 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
(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. The monthly average market price of
natural gas has not recovered to levels experienced during early 2008 and was $4.38 per Mcf in December 2010.
This volatility and the extended declines 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 through
2009 before increasing somewhat in 2010. The increase in 2010 can be attributed partially to increased activity in oil
rich basins as a result of the growing development of unconventional oil reservoirs and an improvement in the price
of oil compared to 2009. Although our average number of rigs operating increased during 2010, it remains well
below the number of our available rigs. Construction of new land drilling rigs in the United States during the last ten
years has significantly contributed to excess capacity. As a result of decreased drilling activity and excess capacity,
our average number of rigs operating has declined significantly from historic highs. 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 and oil would likely result in low demand for our drilling rigs and pressure
pumping services and would adversely affect our operating results, financial condition and cash flows.
A General Excess of Operable Land Drilling Rigs, Increasing Rig Specialization and Excess Pressure
Pumping Equipment 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:
(cid:129) movement of drilling rigs from region to region,
(cid:129) reactivation of land-based drilling rigs, or
(cid:129) construction of new drilling rigs.
Construction of new drilling rigs increased significantly during the last ten years. The addition of new drilling
rigs to the market and the recent decrease in demand has resulted in excess capacity. Similarly, the substantial recent
increase in unconventional resource plays has led to higher demand for pressure pumping services. As a result, we
believe there has been, and we expect there to continue to be, a significant increase in the construction of new
pressure pumping equipment. The addition of new pressure pumping equipment, as well as any general decline in
demand for pressure pumping services, could result in there being substantially more pressure pumping equipment
available than necessary to meet demand. If this were to occur, providers of pressure pumping services will have
difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the
9
future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and
natural gas contract drilling or pressure pumping businesses.
Shortages of Drill Pipe, Replacement Parts, Other Equipment and Materials Adversely Affect Our
Operating Results.
During periods of increased demand for drilling and pressure pumping services, the industry has experienced
shortages of drill pipe, replacement parts, other equipment and materials, including proppants and gels for our
pressure pumping operations. 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 and materials or prevent
operations. These price increases and delays in delivery may require us to increase capital and repair expenditures
and incur higher operating costs. Severe shortages or delays in delivery could limit our ability to operate our drilling
rigs and pressure pumping equipment.
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 Pressure Pumping Equipment and Rig and Other
Acquisitions are Not Assured.
We have increased our drilling rig fleet and pressure pumping horsepower in the past through mergers,
acquisitions and new construction. The land drilling and pressure pumping industries have 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 and providers of pressure pumping services may continue to build new,
high horsepower equipment.
There can be no assurance that we will:
(cid:129) have sufficient capital resources to complete additional acquisitions or build new rigs or pressure pumping
equipment,
10
(cid:129) successfully integrate additional drilling rigs, pressure pumping equipment or other assets,
(cid:129) effectively manage the growth and increased size of our organization, drilling fleet and pressure pumping
equipment,
(cid:129) successfully deploy idle, stacked or additional rigs and pressure pumping equipment,
(cid:129) maintain the crews necessary to operate additional drilling rigs and pressure pumping equipment, or
(cid:129) 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 and pressure pumping equipment.
We may incur substantial indebtedness to finance future acquisitions, build new drilling rigs or build new
pressure pumping equipment 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.
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 be enforceable or 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. It is possible that a customer or insurer could fail or
be unable to meet its indemnification or insurance obligations, which could result in a material loss. Moreover, we
could suffer a material loss if we were to become subject to an unexpected judgment against us for which we are
uninsured, for which indemnification is unenforceable or otherwise not available or that is beyond the amounts we
reserved or anticipated incurring. 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 generally maintain a $1.0 million per occurrence deductible on our workers’
compensation and equipment insurance coverages and a $2.0 million per occurrence self insured retention on our
general liability insurance coverage.
Difficulties Integrating Our Recently Acquired Pressure Pumping Assets Could Adversely Affect Our
Operating Results.
We expect that our recently acquired pressure pumping assets will complement and expand our business.
Successfully integrating the acquired business depends on our ability to integrate the acquired assets and personnel
and to maintain and grow the acquired customer base. We may encounter challenges in integrating the acquired
business with our existing operations and management. We may not be able to fully take advantage of expected
business opportunities, including successfully developing new markets and retaining acquired customers. The
integration of the new business may place additional strain on our management. In addition, the acquired business
may not achieve anticipated results. If the acquired business is not successfully integrated, our operating results
could be adversely affected.
We are Dependent Upon our Subsidiaries to Meet our Obligations Under our Long Term Debt
We have borrowings outstanding under a term loan and our senior notes. These obligations are guaranteed by
each of our existing subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal
payment obligations depends in large part on dividends paid to us by our subsidiaries. If our subsidiaries do not
11
generate sufficient cash flows to pay us dividends, we may be unable to meet our interest and principal payment
obligations.
Environmental Laws and Regulations, Including Violations Thereof 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 and pressure pumping equipment, we may be deemed to be a
responsible party under these laws and regulations.
Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and
Result in Operational Delays.
Members of the U.S. Congress and the U.S. Environmental Protection Agency (the “EPA”) are reviewing more
stringent regulation of hydraulic fracturing, a technology employed by our pressure pumping business, which
involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural
gas production. Both the EPA and the U.S. Congress are studying whether there is any link between hydraulic
fracturing activities and soil or ground water contamination. As part of their respective studies, the House
Subcommittee on Energy and Environment and the EPA each sent requests to a number of companies, including our
company for information on their hydraulic fracturing practices. We have responded to each of the inquiries. In
addition, legislation has been proposed in the U.S. Congress to amend the federal Safe Drinking Water Act to
require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, which could
make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on
allegations that specific chemicals used in the fracturing process are impairing ground water or causing other
damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that
could lead to operational delays or increased operating costs and could result in additional regulatory burdens that
could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing
business. Certain states have adopted or are considering similar disclosure legislation. Additional regulation could
increase the costs of conducting our business and could materially reduce our business opportunities and revenues if
our customers decrease their levels of activity in response to such regulation.
Legislation and Regulation of Greenhouse Gases Could Adversely Affect our Business
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 EPA and the
Canadian provinces of Alberta and British Columbia. In 2007, the U.S. Supreme Court in Massachusetts, et al. v.
Environmental Protection Agency held that carbon dioxide, a GHG, may be regulated as an “air pollutant” under the
Clean Air Act, which could result in future regulations even if the U.S. Congress does not enact new legislation
regarding such emissions. 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
12
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.
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 Texas, Pennsylvania, Ohio, 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.
(Removed and Reserved).
13
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
PART II
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
2009:
First quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $13.50
15.95
Second quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15.98
Third quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18.07
Fourth quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010:
First quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $18.67
16.15
Second quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17.42
Third quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22.67
Fourth quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 7.49
8.56
11.38
14.20
$13.19
11.85
12.52
16.59
(b) Holders
As of February 11, 2011, there were approximately 1,500 holders of record of our common stock.
(c) Dividends
We paid cash dividends during the years ended December 31, 2009 and 2010 as follows:
Per Share
Total
(in thousands)
2009:
Paid on March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on December 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010:
Paid on March 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on June 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on September 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on December 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$0.05
0.05
0.05
0.05
$0.20
$0.05
0.05
0.05
0.05
$0.20
$ 7,655
7,675
7,675
7,676
$30,681
$ 7,677
7,706
7,704
7,709
$30,796
On February 2, 2011, 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, 2011 to holders of record as of March 15, 2011. 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
(d) Securities Authorized for Issuance Under Equity Compensation Plans
Equity compensation plan information as of December 31, 2010 follows:
Plan Category
Equity Compensation Plan Information
Number of
Securities to
be Issued upon
Exercise of
Outstanding
Options,
Warrants and
Rights
(a)
Weighted-Average
Exercise Price
of Outstanding
Options, Warrants
and Rights
(b)
Number of
Securities
Remaining Available
for Future Issuance
under Equity
Compensation Plans
(Excluding Securities
Reflected in
Column(a))
(c)
Equity compensation plans approved by
security holders(1) . . . . . . . . . . . . . . . . . .
7,541,550
Equity compensation plans not approved by
security holders(2) . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . .
168,552
7,710,102
$19.78
$10.23
$19.58
5,763,314
—
5,763,314
(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
(e) Performance Graph
The following graph compares the cumulative stockholder return of our common stock for the period from
December 31, 2005 through December 31, 2010, 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 peer
group consists of BJ Services Company, Bronco Drilling Company, Inc., Helmerich & Payne, Inc., Nabors
Industries, Ltd., Pioneer Drilling Co., Precision Drilling Corp and Superior Well Services, Inc. All of the companies
in our peer group are providers of land-based drilling or pressure pumping services. BJ Services Company and
Superior Well Services, Inc. were acquired by Baker Hughes, Inc. and Nabors Industries, Ltd., respectively during
2010. The graph assumes investment of $100 on December 31, 2005 and reinvestment of all dividends.
Comparison of Cumulative Total Return
(in dollars)
$200
150
100
50
0
2005
2006
2007
2008
2009
2010
Patterson-UTI Energy, Inc.
S&P 500 Index
S&P MidCap
Oil Service Index (OSX)
Peer Group
Company/Index
2005
($)
Patterson-UTI Energy, Inc.
. . . . . . . . . . . . . . . . . . 100.00
Peer Group Index . . . . . . . . . . . . . . . . . . . . . . . . . 100.00
S&P 500 Stock Index . . . . . . . . . . . . . . . . . . . . . . 100.00
Oilfield Service Index (OSX) . . . . . . . . . . . . . . . . 100.00
S&P MidCap Index . . . . . . . . . . . . . . . . . . . . . . . . 100.00
Fiscal Year Ended December 31,
2006
($)
71.28
79.68
115.79
110.35
110.32
2007
($)
61.09
74.95
122.16
167.21
119.12
2008
($)
37.17
36.97
76.96
67.77
75.96
2009
($)
50.37
59.59
97.33
109.89
104.36
2010
($)
71.56
76.24
111.99
139.47
132.16
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, 2010, 2009, 2008, 2007 and 2006, and for each of
the five years in the period ended December 31, 2010 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 reclassi-
fications have been made to the historical financial data to conform with the 2010 presentation. Due to the sale of
our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January
16
2011, the results of operations for those businesses have been reclassified and are presented as discontinued
operations in all periods presented below.
2010
Years Ended December 31,
2009
2007
2008
(In thousands, except per share amounts)
2006
Statement of Operations Data:
Operating revenues:
Contract drilling . . . . . . . . . . . . . . . $1,081,898
350,608
Pressure pumping . . . . . . . . . . . . . .
30,425
Oil and natural gas . . . . . . . . . . . . .
1,462,931
Total . . . . . . . . . . . . . . . . . . . . . .
$ 599,287
161,441
21,218
781,946
$1,804,026
217,494
42,360
2,063,880
$1,741,647
202,812
41,637
1,986,096
$2,169,370
145,671
39,187
2,354,228
Operating costs and expenses:
Contract drilling . . . . . . . . . . . . . . .
Pressure pumping . . . . . . . . . . . . . .
Oil and natural gas . . . . . . . . . . . . .
Depreciation, depletion,
amortization and impairment . . . .
Selling, general and administrative . .
Net (gain) loss on asset disposals . . .
Provision for bad debts . . . . . . . . . .
Embezzlement costs (recoveries) . . .
Acquisition-related expenses . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . .
Other income (expense) . . . . . . . . . . .
Income (loss) from continuing
operations before income taxes . . . .
Income tax expense (benefit) . . . . . . . .
Income (loss) from continuing
655,678
235,100
7,020
333,493
53,042
(22,812)
(2,000)
—
2,485
1,262,006
200,925
(10,171)
357,742
124,100
7,341
289,847
43,935
3,385
3,810
—
—
830,160
(48,214)
(3,341)
1,038,327
147,377
12,793
275,990
43,273
(4,163)
4,350
—
—
1,517,947
545,933
1,425
963,150
117,250
10,864
246,346
42,688
(16,432)
2,875
(43,955)
—
1,322,786
663,310
527
1,002,001
85,529
13,374
193,664
36,770
3,905
5,585
3,081
—
1,343,909
1,010,319
4,657
190,754
72,856
(51,555)
(17,595)
547,358
193,490
663,837
229,350
1,014,976
360,639
operations . . . . . . . . . . . . . . . . . . . . $ 117,898
$ (33,960)
$ 353,868
$ 434,487
$ 654,337
Income (loss) from continuing
operations per common share:
Basic. . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . $
Cash dividends per common share . . . . $
Weighted average number of common
shares outstanding:
0.77
0.76
0.20
$
$
$
(0.22)
(0.22)
0.20
$
$
$
2.29
2.27
0.60
$
$
$
2.78
2.75
0.44
$
$
$
3.94
3.89
0.28
Basic. . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . .
152,772
153,276
152,069
152,069
153,379
154,358
154,755
156,612
165,159
167,200
Balance Sheet Data:
Total assets . . . . . . . . . . . . . . . . . . . . . $3,423,031
—
Borrowings under line of credit . . . . . .
Long term debt (including current
maturities) . . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .
Working capital
398,750
2,187,607
241,445
$2,662,152
—
$2,712,817
—
$2,465,199
50,000
$2,192,503
120,000
—
2,081,700
263,511
—
2,126,942
337,615
—
1,896,030
226,209
—
1,562,466
334,429
17
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, 2010,
our operating revenues consisted of the following (dollars in thousands):
2010
2009
2008
Contract drilling. . . . . . . . . . . . . . . . .
Pressure pumping. . . . . . . . . . . . . . . .
Oil and natural gas. . . . . . . . . . . . . . .
$1,081,898
350,608
30,425
74% $599,287
161,441
24
21,218
2
76% $1,804,026
217,494
21
42,360
3
87%
11
2
$1,462,931
100% $781,946
100% $2,063,880
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, Pennsylvania,
West Virginia and western Canada, while our pressure pumping services are focused primarily in Texas and the
Appalachian Basin. The oil and natural gas properties in which we hold interests are primarily located in Texas and
New Mexico.
Generally, the profitability of our business is impacted most by two primary factors in our contract drilling
segment: our average number of rigs operating and our average revenue per operating day. During 2010, our average
number of rigs operating was 168 compared to 91 in 2009 and 254 in 2008. Our average revenue per operating day
was $17,670 in 2010 compared to $17,950 in 2009 and $19,380 in 2008. We had consolidated net income of
$117 million for 2010 compared to a consolidated net loss of $38.3 million for 2009. The increase in consolidated
net income was primarily due to our contract drilling segment experiencing an increase in the average number of
rigs operating. Additionally, our pressure pumping segment experienced an increase in large multi-stage fracturing
jobs in 2010 compared to 2009. This increase includes the fourth quarter contribution of a pressure pumping
business we acquired on October 1, 2010, which significantly expanded our pressure pumping operations into new
markets in the fourth quarter of 2010.
Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and 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. After reaching a peak in June 2008, there was a significant
decline in oil and natural gas prices and a substantial deterioration in the global economic environment. As part of
this deterioration, there was substantial uncertainty in the capital markets and access to financing was 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 number of rigs operating from a high of
283 in October 2008 to a low of 60 in June 2009. Our monthly average number of rigs operating has subsequently
increased from the mid-year low in 2009 to 196 in December 2010. The decline in commodity prices and
deterioration in the global economy resulted in certain of our customers experiencing an inability to pay suppliers,
including us. 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. Please see “Risk Factors” in Item 1A of this Report.
We believe that our liquidity as of December 31, 2010, which includes approximately $241 million in working
capital and approximately $359 million available under our $400 million revolving credit facility, together with
cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to
build new equipment, make improvements to our existing equipment and pay cash dividends. 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 flows from operating activities borrowing capacity under our revolving
18
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.
Commitments and Contingencies — As of December 31, 2010, we maintained letters of credit in the aggregate
amount of $41.2 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, 2010, no
amounts had been drawn under the letters of credit.
As of December 31, 2010, we had commitments to purchase approximately $267 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, 2010, 2009 and 2008, revenue earned in Canada was
$65.7 million, $45.4 million and $88.5 million, respectively. Additionally, we had long-lived assets located in
Canada of $70.7 million and $69.2 million as of December 31, 2010 and 2009, respectively. As of December 31,
2010, we had 356 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas
operators primarily in Texas and the Appalachian Basin. Pressure pumping services are primarily well stimulation
and cementing for completion of new wells and remedial work on existing wells. 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 continue to 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. In connection with our long term
planning process, we evaluated our then-current fleet of marketable drilling rigs in 2010, 2009 and 2008 and
identified four, 23 and 22 rigs, respectively, that we determined would no longer be marketed as rigs. The
components comprising these rigs were evaluated, and those components with continuing utility to our other
marketed rigs 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 $4.2 million in 2010, $10.5 million in
2009 and $10.4 million in 2008 was expensed in our consolidated statements of operations as an impairment charge.
19
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 in 2008. Due to a continued decrease in the operating levels in our
contract drilling segment through the first three quarters of 2009, we again deemed it necessary to perform an
impairment assessment of long-lived assets in our contract drilling segment in 2009. Based on the estimated
undiscounted cash flows associated with the assets, we determined that no impairment was indicated in 2009. In
light of the recent favorable trends in rig utilization and revenue per operating day experienced by us and our peers,
we concluded that no triggering event had occurred in 2010 with respect to our contract drilling segment. We also
concluded that no triggering event had occurred with respect to our pressure pumping segment in 2010, 2009 or
2008. Impairment considerations related to our oil and natural gas segment are discussed below.
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 economic viability of the respective projects. If no progress has
been made in assessing the reserves and economic viability of a project after one year following the completion of
drilling, we consider the well costs 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 for each
respective field.
We review our proved oil and natural gas properties for impairment whenever 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 cash flow estimates are 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 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. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our
impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms
and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are
expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately
$792,000, $3.7 million and $4.4 million for the years ended December 31, 2010, 2009 and 2008, respectively, and 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. 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 goodwill may have 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 impairment assessment 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 values. Any excess
20
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 average 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 our contract drilling reporting unit as the estimated fair value of that reporting unit exceeded its carrying
value. However, 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 approximately
$10.0 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 performed our annual goodwill impairment assessment as of December 31, 2009 related to the $86.2 mil-
lion 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 the 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.
We performed our annual goodwill impairment assessment as of December 31, 2010. In completing the first
step of our analysis, we estimated our enterprise value based on our market capitalization as determined by
reference to the closing price of our common stock during the fifteen days before and after year end. We allocated
the enterprise value to our reporting units and determined that the fair values of our reporting units were in excess of
their carrying value. As a result, we concluded that no impairment of goodwill was indicated as of December 31,
2010.
During the fourth quarter of 2010, we recorded goodwill in our pressure pumping reporting unit in connection
with our acquisition of a pressure pumping business. The goodwill associated with this acquisition was estimated to
be $67.6 million.
In the event that market conditions weaken, we may be required to record an impairment of goodwill in our
contract drilling or pressure pumping reporting units 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 arrange-
ments. 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 the risks therein, we follow the completed-contract method of accounting for such arrangements.
21
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 as revenue reimbursements received from third
parties for out-of-pocket expenses and account for those out-of-pocket expenses as direct costs. Except for two
wells drilled under footage contacts in 2009, all of the wells we drilled in 2010, 2009 and 2008 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
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:
(cid:129) allowance for doubtful accounts,
(cid:129) depreciation and depletion,
(cid:129) fair values of assets acquired and liabilities assumed in acquisitions,
(cid:129) goodwill and long-lived asset impairments, and
(cid:129) 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, 2010, we had working capital of $241 million, including cash and cash equivalents of
$27.6 million. During 2010, our sources of cash flow included:
(cid:129) $526 million from operating activities,
(cid:129) $400 million in proceeds from long term debt,
(cid:129) $42.6 million in proceeds from the disposal of our drilling and completion fluids business, and
(cid:129) $29.4 million in proceeds from the disposal of property and equipment.
During 2010, we used $238 million to acquire pressure pumping and electric wireline businesses, $30.8 million
to pay dividends on our common stock, $10.8 million to pay debt issuance costs, $1.9 million to repurchase shares
of our common stock and $738 million:
(cid:129) to build new drilling rigs,
(cid:129) to make capital expenditures for the betterment and refurbishment of our drilling rigs,
(cid:129) to acquire and procure drilling equipment and facilities to support our drilling operations,
(cid:129) to fund capital expenditures for our pressure pumping segment, and
(cid:129) to fund investments in oil and natural gas properties on a working interest basis.
22
We paid cash dividends during the year ended December 31, 2010 as follows:
Paid on March 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on June 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on September 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on December 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash dividends. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Per Share
$0.05
0.05
0.05
0.05
$0.20
Total
(In thousands)
$ 7,677
7,706
7,704
7,709
$30,796
On February 2, 2011, 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, 2011 to holders of record as of March 15, 2011. 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, authorizing purchases of up to
$250 million of our common stock in open market or privately negotiated transactions. During the year ended
December 31, 2010, we purchased 8,743 shares of our common stock under this program at a cost of approximately
$123,000. As of December 31, 2010, we are authorized to purchase approximately $113 million of our outstanding
common stock under this program.
On August 19, 2010, we entered into a Credit Agreement (the “2010 Credit Agreement”). The 2010 Credit
Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan
facility. The 2010 Credit Agreement replaced a previous unsecured revolving credit facility.
The revolving credit facility permits aggregate borrowings of up to $400 million and contains a letter of credit
facility that is limited to $150 million and a swing line facility that is limited to $40 million. Subject to customary
conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility be
increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for the
revolving credit facility is August 19, 2013.
The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan
facility is payable in quarterly principal installments commencing November 19, 2010, and the installment amounts
vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the
original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal
amount for the next subsequent three quarterly installments, and the remainder due at maturity. The maturity date
for the term loan facility is August 19, 2014.
Loans under the 2010 Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base
rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate
loans varies from 1.75% to 2.75%, in each case determined based upon our debt to capitalization ratio. As of
December 31, 2010, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate
loans was 1.75%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times
the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the
lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon our debt to
capitalization ratio and was 0.50% as of December 31, 2010.
The 2010 Credit Agreement contains customary representations, warranties, indemnities and affirmative and
negative covenants. The 2010 Credit Agreement also requires compliance with two financial covenants. We must
not permit our debt to capitalization ratio to exceed 45% at any time. The 2010 Credit Agreement generally defines
the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such
indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most
recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter
to be less than 3.00 to 1.00. The 2010 Credit Agreement generally defines the interest coverage ratio as the ratio of
earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to
interest charges for the same period. We were in compliance with these financial covenants as of December 31,
23
2010. We do not expect that the restrictions and covenants will impair our ability to operate or react to opportunities
that might arise.
As of December 31, 2010, we had $98.8 million principal amount outstanding under the term loan facility at an
interest rate of 3.125% and no borrowings outstanding under the revolving credit facility. We had $41.2 million in
letters of credit outstanding at December 31, 2010, and as a result, we had available borrowing capacity of
approximately $359 million at that date.
On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our
4.97% Series A Senior Notes due October 5, 2020 (the “Notes”) in a private placement. A portion of the proceeds
from the Notes was used to repay a $200 million borrowing on our revolving credit facility, which had been drawn to
fund a portion of a business acquisition that closed on October 1, 2010.
The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal amount of the
Notes. We will pay interest on the Notes on April 5 and October 5 of each year commencing on April 5, 2011. The
Notes will mature on October 5, 2020. The Notes are prepayable at our option, in whole or in part, provided that in
the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal
amount of the Notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid,
plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note
purchase agreement. We must offer to prepay the Notes upon the occurrence of any change of control. In addition,
we must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not
timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid Note is
100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.
The note purchase agreement requires compliance with two financial covenants. We must not permit our debt
to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to
capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus
consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal
quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to
1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the four prior
quarters of EBITDA to interest charges for the same period. We were in compliance with these financial covenants
as of December 31, 2010. We do not expect that the restrictions and covenants will impair our ability to operate or
react to opportunities that might arise.
Events of default under the note purchase agreement include failure to pay principal or interest when due,
failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a
threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a
change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing,
then holders of a majority in principal amount of the Notes have the right to declare all the notes then-outstanding to
be immediately due and payable. In addition, if we default in payments on any Note, then until such defaults are
cured, the holder thereof may declare all the Notes held by it to be immediately due and payable.
We believe that our current level of cash, short-term investments and borrowing capacity available under our
revolving credit facility, together with cash expected to be generated from our operating activities, should be
sufficient to fund our current plans to build new equipment, make improvements to our existing equipment and pay
cash dividends.
From time to time, opportunities to expand our business, including acquisitions and the building of new
equipment, 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.
24
Contractual Obligations
The following table presents information with respect to our contractual obligations as of December 31, 2010
(dollars in thousands):
Payments due by period
Total
Less Than 1
Year
1-3 Years
3-5 Years
More Than 5
Years
Borrowings under revolving credit
facility(1) . . . . . . . . . . . . . . . . . . $
— $
— $ — $
— $
Borrowings under term loan(2) . . . .
Interest on term loan(3) . . . . . . . .
Series A Senior Notes(4) . . . . . . . . .
98,750
9,371
300,000
6,250
3,097
—
22,500
5,267
—
70,000
1,007
—
—
—
—
300,000
Interest on Series A Senior
Notes(5) . . . . . . . . . . . . . . . . .
145,546
14,910
29,820
29,820
70,996
Commitments to purchase
equipment(6) . . . . . . . . . . . . . . . .
266,567
266,567
—
—
—
$820,234
$290,824
$57,587
$100,827
$370,996
(1) No borrowings were outstanding on our revolving credit facility as of December 31, 2010. Any borrowings that
are drawn on our revolving credit facility would be due at maturity August 19, 2013.
(2) Represents repayments of borrowing under the term loan portion of the 2010 Credit Agreement. The term loan
matures on August 19, 2014.
(3) Interest to be paid on term loan using 3.25% rate in effect as of December 31, 2010.
(4) Principal repayment of the Series A Senior Notes is required at maturity on October 5, 2020.
(5) Interest to be paid on the Series A Senior Notes using 4.97% coupon rate.
(6) Represents commitments to purchase major equipment to be delivered in 2011 based on expected delivery
dates.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements at December 31, 2010.
Results of Operations
Comparison of the years ended December 31, 2010 and 2009
The following tables summarize operations by business segment for the years ended December 31, 2010 and
2009:
Contract Drilling
Year Ended December 31,
2010
2009
% Change
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . .
Depreciation and impairment . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenue per operating day . . . . . . . . . . . . . . . . . . . . .
Average direct operating costs per operating day. . . . . . . . . . .
Average rigs operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25
(Dollars in thousands)
$599,287
$357,742
$
4,340
$248,424
$ (11,219)
33,394
17.95
10.71
91
$395,376
$1,081,898
$ 655,678
$
5,279
$ 280,458
$ 140,483
61,244
17.67
10.71
168
$ 655,550
$
$
$
$
80.5%
83.3%
21.6%
12.9%
N/M
83.4%
(1.6)%
0.0%
84.6%
65.8%
The demand for our contract drilling services is impacted by the market price of natural gas and 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 and oil for each of
the fiscal quarters and full year in 2010 and 2009 follows:
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Year
2009:
Average natural gas price per
Mcf(1) . . . . . . . . . . . . . . . . . . . .
Average oil price per Bbl(2) . . . . . .
2010:
Average natural gas price per
Mcf(1) . . . . . . . . . . . . . . . . . . . .
Average oil price per Bbl(2) . . . . . .
$ 4.71
$42.91
$ 3.82
$59.44
$ 3.26
$68.20
$ 4.46
$76.06
$ 4.06
$61.65
$ 5.30
$78.64
$ 4.45
$77.79
$ 4.41
$76.05
$ 3.91
$85.10
$ 4.52
$79.40
(1) The average natural gas price represents the Henry Hub Spot price as reported by the United States Energy
Information Administration.
(2) The average oil price represents the average monthly Cushing, OK WTI spot price as reported by the United
States Energy Information Administration.
Revenues and direct operating costs increased in 2010 compared to 2009 as a result of an increase in the number
of operating days. The increase in operating days was due to increased demand largely caused by higher prices for
natural gas and oil. Our average number of rigs operating during 2009 included an average of approximately six rigs
operating under term contracts that earned standby revenues of $22.3 million. Rigs on standby earn a discounted
dayrate as they do not have crews and have lower costs. We had no significant standby revenue associated with rigs
operating under term contracts in 2010. We recognized approximately $8.0 million of revenues during 2009 from the
early termination of term contracts. We had no such revenue from the early termination of term contracts in 2010.
Selling, general and administrative expenses increased in 2010 primarily as a result of increased personnel costs to
support increased activity levels. Significant capital expenditures were incurred in 2010 and 2009 to build new drilling
rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe,
drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation
expense increased as a result of capital expenditures. Depreciation and impairment expense includes approximately
$4.2 million in 2010 and approximately $10.5 million in 2009 of impairment charges related to drilling equipment on
drilling rigs that were removed from our marketable fleet. We removed four rigs from our marketable fleet in 2010 and
removed 23 rigs from our marketable fleet in 2009.
Pressure Pumping
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fracturing jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenue per fracturing job . . . . . . . . . . . . . . . . . . . . . .
Average revenue per other job. . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenue per total job . . . . . . . . . . . . . . . . . . . . . . . . . .
Average direct operating costs per total job . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26
% Change
2010
Year Ended December 31,
2009
(Dollars in thousands)
$161,441
$124,100
$
8,735
$ 27,589
1,017
$
1,579
5,399
6,978
70.88
$
9.17
$
23.14
$
$
17.78
$ 43,144
$350,608
$235,100
$ 12,590
$ 40,724
$ 62,194
1,527
6,047
7,574
$ 180.21
$ 12.47
$ 46.29
$ 31.04
$ 51,064
117.2%
89.4%
44.1%
47.6%
N/M
(3.3)%
12.0%
8.5%
154.2%
36.0%
100.0%
74.6%
18.4%
Revenues and direct operating costs increased primarily as a result of the increase in the number of larger
multi-stage fracturing jobs, which was driven by higher demand for services associated with unconventional
reservoirs. Also contributing to these increases was our acquisition of a pressure pumping business on October 1,
2010 which significantly expanded the size of our fleet of pressure pumping equipment and the markets in which we
provide pressure pumping services. This acquisition was accounted for as a business combination and the results of
operations of the acquired business are included in our pressure pumping segment results from the date of
acquisition. The acquired business contributed revenue of $84.7 million and operating income of $22.8 million to
our operating results during the year ended December 31, 2010.
Our customers have increased their activities in the development of unconventional reservoirs resulting in an
increase in larger multi-stage fracturing jobs associated therewith. As a result, we have experienced an increase in
the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed.
Average revenue per other job increased as a result of increased pricing for the services provided and a change in job
mix. Selling, general and administrative expenses in 2010 include $1.5 million associated with the acquired
business. The remaining increase in selling, general and administrative expenses is due to additional costs necessary
to support increased business activity in 2010. Significant capital expenditures have been incurred in recent years to
add capacity in our pressure pumping segment. Depreciation and amortization expense in 2010 includes
$1.0 million in amortization of intangible assets and $4.7 million in depreciation of property and equipment
associated with the acquired business. The remaining increase in depreciation in 2010 compared to 2009 is a result
of our recent capital expenditures.
Oil and Natural Gas Production and Exploration
2010
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $30,425
Direct operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,020
Depreciation, depletion and impairment . . . . . . . . . . . . . . . . . . . . $10,950
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,455
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23,067
877
Average net daily oil production (Bbls) . . . . . . . . . . . . . . . . . . . . .
Average net daily gas production (Mcf) . . . . . . . . . . . . . . . . . . . .
2,788
Average oil sales price (per Bbl). . . . . . . . . . . . . . . . . . . . . . . . . . $ 77.26
5.60
Average gas sales price (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . $
% Change
Year Ended December 31,
2009
(Dollars in thousands, except
commodity prices)
$21,218
$ 7,341
$12,927
$
950
$ 7,341
761
3,225
$ 58.09
4.32
$
43.4%
(4.4)%
(15.3)%
N/M
214.2%
15.2%
(13.6)%
33.0%
29.6%
Revenues increased due to higher average sales prices of oil and natural gas and increased oil production
partially offset by a decline in natural gas production. Average net daily oil production increased primarily due to
the addition of new wells. Average net daily natural gas production decreased primarily due to production declines
on existing wells. Depreciation, depletion and impairment expense in 2010 includes approximately $792,000 of oil
and natural gas property impairments compared to approximately $3.7 million of oil and natural gas property
impairments in 2009. Depletion expense increased approximately $915,000 in 2010 compared to 2009. Capital
expenditures increased in 2010 as a result of greater drilling activity and increased costs per well.
Corporate and Other
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . $ 35,173
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,361
Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (2,000)
Net (gain) loss on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . $(22,812)
Acquisition-related expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,485
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,674
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,772
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
927
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,409
2010
% Change
Year Ended December 31,
2009
(Dollars in thousands)
$30,860
907
$
$ 3,810
$ 3,385
$ —
$
381
$ 4,148
$
426
$ 6,785
14.0%
50.1%
N/M
N/M
N/M
339.4%
207.9%
117.6%
23.9%
27
Selling, general and administrative expense increased in 2010 primarily as a result of increased personnel
costs. The provision for bad debts in 2009 resulted from an increase in our reserve on specific account balances
based on the deteriorating economic and credit environment at the time. The negative provision for bad debts in
2010 is the result of reductions in our reserve for specific accounts due to improved industry conditions. 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. The gain on asset disposals in 2010 includes a
gain of $20.1 million related to the sale of certain rights to explore and develop zones deeper than depths that we
generally target for certain of the oil and natural gas properties in which we have working interests. Losses on asset
disposals in 2009 were primarily related to the disposal of contract drilling equipment. Acquisition-related expenses
in 2010 were incurred in connection with the acquisition of pressure pumping and electric wireline businesses
during the fourth quarter of 2010. These expenses included certain legal and other professional fees directly related
to the transaction, fees incurred in connection with the title transfers of the acquired equipment and transition costs
related to information technology. Interest income increased due to the collection of interest on a customer account
as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest expense in 2010
includes $3.3 million due to the recognition of remaining deferred financing costs associated with a revolving credit
facility that was replaced in August 2010, and $1.3 million due to the recognition of financing costs associated with
a bridge facility that expired unused on September 30, 2010. The remainder of the 2010 increase relates to interest
charges and the amortization of debt issuance costs associated with the $100 million term loan entered into in
August 2010 and the $300 million Senior Notes issued in October 2010. Capital expenditures increased in 2010 due
to the ongoing implementation of a new enterprise resource planning system.
Discontinued Operations:
Year Ended December 31,
2010
2009
% Change
(Dollars in thousands)
$ —
Electric wireline revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,712
$ —
Electric wireline direct operating costs . . . . . . . . . . . . . . . . . . . . . . $4,962
$79,786
Drilling and completion fluids revenue . . . . . . . . . . . . . . . . . . . . . . $3,737
$74,180
Drilling and completion fluids direct operating costs . . . . . . . . . . . . $3,307
$ 7,192
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . $ 358
$ 2,287
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 166
Impairment of assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . $2,155
$ 1,900
Net gain on asset disposals/retirements . . . . . . . . . . . . . . . . . . . . . . $ — $ (125)
890
Other operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $
$ (2,208)
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (543)
$ (4,330)
Loss from discontinued operations, net of income taxes . . . . . . . . . $ (956)
N/M
N/M
(95.3)%
(95.5)%
(95.0)%
(92.7)%
13.4%
(100.0%
(100.0)%
(75.4)%
(77.9)%
On January 27, 2011, we sold our electric wireline business, which had been acquired by us on October 1,
2010. The results of operations of this business have been classified as a discontinued operation and the assets held
for sale at December 31, 2010 are presented at net realizable value in the consolidated balance sheet. On January 20,
2010, we sold our drilling and completion fluids services business which had previously been presented as one of
our reportable operating segments. Due to our exit from this business, we have classified our drilling and
completion fluids operating segment as a discontinued operation. Impairment of assets held for sale in 2010
and 2009 reflects the transaction-related costs recorded to reduce the carrying value of the assets sold to their net
realizable value at December 31, 2010, and 2009.
28
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:
Contract Drilling
2009
% Change
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . .
Depreciation and impairment . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenue per operating day . . . . . . . . . . . . . . . . . . . . .
Average direct operating costs per operating day. . . . . . . . . . .
Average rigs operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2008
(Dollars in thousands)
$1,804,026
$1,038,327
$
5,363
$ 239,700
$ 520,636
93,068
19.38
11.16
254
$ 360,645
$599,287
$357,742
$ 4,340
$248,424
$ (11,219)
33,394
$ 17.95
$ 10.71
91
$395,376
$
$
(66.8)%
(65.5)%
(19.1)%
3.6%
N/M
(64.1)%
(7.4)%
(4.0)%
(64.2)%
9.6%
The demand for our contract drilling services is impacted by the market price of natural gas and 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 and oil for each of
the fiscal quarters and full year in 2009 and 2008 follow:
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
Year
2008:
Average natural gas price per
Mcf(1) . . . . . . . . . . . . . . . . . . . .
Average oil price per Bbl(2) . . . . . .
2009:
Average natural gas price per
Mcf(1) . . . . . . . . . . . . . . . . . . . .
Average oil price per Bbl(2) . . . . . .
$ 8.92
$97.94
$ 11.74
$123.95
$ 9.28
$118.05
$ 6.60
$58.35
$ 9.13
$99.57
$ 4.71
$42.91
$ 3.82
$ 59.44
$ 3.26
$ 68.20
$ 4.46
$76.06
$ 4.06
$61.65
(1) The average natural gas price represents the Henry Hub Spot price as reported by the United States Energy
Information Administration.
(2) The average oil price represents the average monthly Cushing, OK WTI 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 operating under term contracts that earned standby revenues of $22.3 million. This
represented an increase from an average of approximately one rig operating under a 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 expense increased as a result of those capital expenditures. Depreciation and impairment
29
expense includes approximately $10.5 million in 2009 and approximately $10.4 million in 2008 of impairment
charges related to drilling equipment on drilling rigs that were removed from our marketable fleet. We removed 23
rigs from our marketable fleet in 2009 and removed 22 rigs from our marketable fleet in 2008.
Pressure Pumping
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . .
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fracturing jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenue per fracturing job . . . . . . . . . . . . . . . . . . . . . .
Average revenue per other job. . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenue per total job . . . . . . . . . . . . . . . . . . . . . . . . . .
Average direct operating costs per total job . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
% Change
2009
Year Ended December 31,
2008
(Dollars in thousands)
$217,494
$147,377
8,498
$
$ 19,600
$ 42,019
2,898
9,162
12,060
49.62
$
8.04
$
18.03
$
$
12.22
$ 61,289
$161,441
$124,100
$ 8,735
$ 27,589
$ 1,017
1,579
5,399
6,978
$ 70.88
9.17
$
$ 23.14
$ 17.78
$ 43,144
(25.8)%
(15.8)%
2.8%
40.8%
(97.6)%
(45.5)%
(41.1)%
(42.1)%
42.8%
14.1%
28.3%
45.5%
(29.6)%
Our customers have increased their activities in the development of unconventional reservoirs resulting in an
increase in larger multi-stage fracturing jobs associated therewith. As a result, we have experienced an increase in
the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. In
2009 we experienced a decrease in smaller traditional pressure pumping jobs due to depressed commodity prices,
which contributed to the overall decrease in revenue and direct operating costs. 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 and lower commodity prices caused a slower increase in
customer activity than we had expected, negatively impacting the profitability of this business. Significant capital
expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of our
recent capital expenditures.
Oil and Natural Gas Production and Exploration
2009
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $21,218
Direct operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,341
Depreciation, depletion and impairment . . . . . . . . . . . . . . . . . . . . $12,927
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
950
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,341
761
Average net daily oil production (Bbls) . . . . . . . . . . . . . . . . . . . . .
Average net daily gas production (Mcf) . . . . . . . . . . . . . . . . . . . .
3,225
Average oil sales price (per Bbl). . . . . . . . . . . . . . . . . . . . . . . . . . $ 58.09
4.32
Average gas sales price (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . $
% Change
Year Ended December 31,
2008
(Dollars in thousands, except
commodity prices)
$42,360
$12,793
$15,856
$13,711
$22,981
801
3,755
$ 98.70
9.77
$
(49.9)%
(42.6)%
(18.5)%
(93.1)%
(68.1)%
(5.0)%
(14.1)%
(41.1)%
(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 of oil and natural gas property impairments compared to approximately $4.4 million of
oil and natural gas property impairments in 2008. Depletion expense decreased approximately $2.3 million
30
primarily due to lower production and the impact of decreases in the carrying value of properties resulting from
previous impairment charges. Capital expenditures decreased in 2009 as a result of declines in commodity prices.
Corporate and Other
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . $30,860
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
907
Provision for bad debts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,810
Net (gain) loss on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,385
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
381
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,148
426
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,785
2009
% Change
Year Ended December 31,
2008
(Dollars in thousands)
$29,412
$
834
$ 4,350
$ (4,163)
$ 1,553
630
$
502
$
511
$
4.9%
8.8%
(12.4)%
N/M
(75.5)%
558.4%
(15.1)%
N/M
Selling, general and administrative expense increased in 2009 primarily as a result of increased professional
fees. The provision for bad debts resulted from an increase in our reserve on specific account balances based on the
deteriorating economic and credit environment in 2008 and 2009. 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 debt issuance costs and increased fees associated with outstanding letters of credit and the unused portion of the
revolving credit facility that was put into place in 2009. Capital expenditures increased in 2009 due to the purchase
and ongoing implementation of a new enterprise resource planning system.
2009
% Change
Discontinued Operations:
Year Ended December 31,
2008
(Dollars in thousands)
$145,246
Drilling and completion fluids revenue . . . . . . . . . . . . . . . . . . . . $79,786
$126,900
Drilling and completion fluids direct operating costs . . . . . . . . . . $74,180
$ 10,110
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . $ 7,192
2,830
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,287
$
9,964
Goodwill impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $
—
$
Impairment of assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . $ 1,900
(155)
$
Net gain on asset disposals/retirements . . . . . . . . . . . . . . . . . . . . $ (125)
—
$
890
Other operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7
Net interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $
$
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (2,208)
2,389
$ (6,799)
Loss from discontinued operations, net of income taxes . . . . . . . . $ (4,330)
(45.1)%
(41.5)%
(28.9)%
(19.2)%
(100.0)%
N/M
(19.4)%
N/M
(100.0)%
N/M
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. Due to our exit from this business, we have 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, were 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 transaction-related costs
recorded to reduce the carrying value of the assets sold to their net realizable value at December 31, 2009. In 2008,
31
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
Income (loss) from continuing operations before income tax . . .
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
2010
Year Ended December 31,
2009
(Dollars in thousands)
$(51,555)
(17,595)
34.1%
38.2%
$190,754
72,856
$547,358
193,490
35.3%
The effective tax rate is a result of a Federal rate of 35.0% adjusted as follows:
2010
2009
2008
Statutory tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35.0% 35.0% 35.0%
4.7
1.1
(5.7)
2.3
0.1
(0.2)
1.7
(1.2)
(0.2)
Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
38.2% 34.1% 35.3%
For 2008, the permanent difference indicated above was 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) and allows a deduction of
6% in both 2008 and 2009 and 9% in 2010 and thereafter on the lesser of qualified production activities income or
taxable income. The permanent differences for 2010 and 2009 reflect the recapture of a portion of this deduction
due to the planned carryback of the 2010 net operating loss to prior years and the carryback of the 2009 net operating
loss to prior years. This recapture resulted in a negative effective rate impact in 2009 due to the Company having a
loss before income taxes in that year.
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 $147 million in 2010, $101 million in 2009 and
$65.4 million in 2008.
On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign
corporation for Federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the
United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as
a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets.
As a result of the above conversion, our Canadian assets are no longer subject to United States taxation,
provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we
have elected to permanently reinvest these unremitted earnings in Canada, and intend to do so for the foreseeable
future. As a result, no deferred United States Federal or state income taxes have been provided on such unremitted
foreign earnings, which totaled approximately $6.3 million as of December 31, 2010.
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 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 United States Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly
32
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 before recovering somewhat in 2010. Construction of new land drilling
rigs in the United States during the last ten years has significantly contributed to excess capacity. As a result of these
factors, our average number of rigs operating has declined significantly from historic highs. 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 and oil would likely result in lower demand for our drilling rigs
and pressure pumping services 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, 2010. We believe that inflation will not have a significant near-term impact on our financial position.
Recently Issued Accounting Standards
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. Prior to 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 October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-
deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined
unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement
consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective
and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a
multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements
will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy
for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The
selling price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-
specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence
nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements
entered into in fiscal years beginning on or after June 15, 2010 and became effective for us on January 1, 2011. The
adoption of this standard did not have a material impact on our consolidated financial position, results of operations
or cash flows.
In December 2010, the FASB issued an accounting standard update that addresses the disclosure of supple-
mentary pro forma information for business combinations. This update clarifies that when public entities are
required to disclose pro forma information for business combinations that occurred in the current reporting period,
the pro forma information should be presented as if the business combination occurred as of the beginning of the
previous fiscal year when comparative financial statements are presented. This update is effective prospectively for
business combinations for which the acquisition date is on or after the beginning of the first annual reporting period
33
beginning on or after December 15, 2010. Early adoption is permitted. We elected to early adopt this update and this
early adoption did not have an impact on our consolidated financial position, results of operations or cash flows.
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
term credit facility or our revolving credit facility. Interest is paid on the outstanding principal amount of
borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges
from 2.75% to 3.75% and the margin on base rate loans ranges from 1.75% to 2.75%, based on our debt to
capitalization ratio. At December 31, 2010, the margin on LIBOR loans was 2.75% and the margin on base rate
loans was 1.75%. As of December 31, 2010, we had no borrowings outstanding under our revolving credit facility
and $98.8 million outstanding under our term credit facility at an interest rate of 3.125%. The interest rate on the
borrowing outstanding under our term credit facility is variable and adjusts at each interest payment date based on
our election of LIBOR or the base rate. A one percent increase in the interest rate on the borrowing outstanding
under our term credit facility as of December 31, 2010 would increase our annual cash interest expense by
$987,500.
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, 2010, 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, 2010, based on the Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our man-
agement has concluded that our internal control over financial reporting was effective as of December 31, 2010.
34
Our wholly-owned subsidiaries, Universal Pressure Pumping, Inc. (“UPP”) and Universal Wireline, Inc.
(“UWL”), were excluded from our evaluation of the effectiveness of our internal control over financial reporting as
of December 31, 2010. UPP and UWL were formed in 2010 for the purpose of acquiring the assets of pressure
pumping and wireline businesses in a business acquisition which closed on October 1, 2010. These subsidiaries
were excluded from the scope of our review due to the fact that the acquisition closed in the fourth quarter of 2010,
at which time we began integrating the acquired businesses into our existing internal controls over financial
reporting. The acquired businesses represented approximately 6 percent of consolidated revenues for the year ended
December 31, 2010 and approximately 9 percent of consolidated total assets as of December 31, 2010.
The effectiveness of our internal control over financial reporting as of December 31, 2010 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 which is incorporated by reference into Item 8 of this Report.
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. As discussed above, we began integrating the acquired pressure pumping and wireline
businesses into our existing internal control over financial reporting during the most recently completed fiscal
quarter.
Item 9B. Other Information
None.
35
PART III
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.
36
Item 15. Exhibits and Financial Statement Schedule.
(a)(1) Financial Statements
PART IV
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.
2.1
2.2
2.3
3.1
3.2
3.3
4.1
4.2
4.3
4.4
10.1
10.2
Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino
Acquisition Company (n/k/a Universal Pressure Pumping, Inc.), Key Energy Pressure Pumping Services,
LLC, Key Electric Wireline Services, LLC and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1
to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure
Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy Pressure Pumping
Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.2 to the
Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and
incorporated herein by reference).
Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure
Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy Pressure Pumping
Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.3 to the
Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and
incorporated herein by reference).
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).
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).
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).
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).
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).
Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2).
Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to
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).
For additional material contracts, see Exhibits 4.1, 4.2 and 4.4.
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).*
37
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
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).*
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).*
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).*
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).*
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).*
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).*
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).*
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).*
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).
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).
Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010
as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).*
Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27,
2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by
reference).*
Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010
as Exhibit 10.3 to the Company’s Current Report on Form 8-K and incorporated herein by reference).*
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 (filed February 19, 2010 as Exhibit 10.9 to
the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated
herein by reference).*
Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI
Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the Company’s
Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by
reference).*
Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005
Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.5 to the Company’s Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).*
38
10.19 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).*
10.20 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).*
10.21 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).*
10.22 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).*
10.23 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).*
10.24 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).*
10.25 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).*
10.26 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).*
10.27 Credit Agreement dated August 19, 2010, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo
Bank, N.A., as administrative agent, letter of credit issuer and lender and each of the other letter of credit
issuer and lender parties thereto (filed August 19, 2010 as Exhibit 10.1 to the Company’s Current Report
on Form 8-K and incorporated herein by reference).
31.2
21.1
23.1
31.1
10.28 Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the
purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s Current Report on
Form 8-K and incorporated herein by reference).
Subsidiaries of the Registrant.
Consent of Independent Registered Public Accounting Firm.
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange
Act of 1934, as amended.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange
Act of 1934, as amended.
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.
The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year
ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the
Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated
Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, and
(v) Notes to Consolidated Financial Statements, tagged as blocks of text.
32.1
101
* Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.
39
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008 . . . . . . .
Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2010,
2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008 . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statement Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
F-2
F-3
F-4
F-5
F-6
F-7
S-1
F-1
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, 2010
and 2009, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2010 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, 2010, 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 misstate-
ments. 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded
Universal Pressure Pumping, Inc. and Universal Wireline, Inc. from its assessment of internal control over financial
reporting as of December 31, 2010 because they were formed in 2010 to acquire certain pressure pumping and
wireline businesses in a business combination during the fourth quarter of 2010. We have also excluded Universal
Pressure Pumping, Inc. and Universal Wireline, Inc. from our audit of internal control over financial reporting. As of
December 31, 2010, Universal Pressure Pumping, Inc. and Universal Wireline, Inc. were wholly-owned subsidiaries
whose total assets and total revenues represented 9 percent and 6 percent, respectively, of the related consolidated
financial statement amounts as of and for the year ended December 31, 2010.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 14, 2011
F-2
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
2010
2009
(In thousands,
except share data)
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accounts receivable, net of allowance for doubtful accounts of $5,114 and
27,612
$
49,877
$10,911 at December 31, 2010 and 2009, respectively . . . . . . . . . . . . . . . . . .
Federal and state income taxes receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets held for sale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill and intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deposits on equipment purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
337,167
75,062
17,215
26,815
23,370
50,169
557,410
2,620,900
179,683
51,084
13,954
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,423,031
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 162,400
147,315
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,250
Current portion of long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
315,965
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
392,500
Long term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
511,422
Deferred tax liabilities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,537
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,235,424
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and contingencies (see Note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Stockholders’ equity:
164,498
118,869
6,941
32,877
42,424
40,475
455,961
2,110,402
86,234
914
8,641
$2,662,152
$
83,700
108,750
—
192,450
—
381,656
6,346
580,452
—
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued . .
Common stock, par value $.01; authorized 300,000,000 shares with 181,537,568
and 180,828,773 issued and 154,193,754 and 153,610,785 outstanding at
December 31, 2010 and 2009, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock, at cost, 27,343,814 shares and 27,217,988 shares at
—
—
1,815
796,641
1,987,999
21,597
1,808
781,635
1,901,853
14,996
(620,445)
December 31, 2010 and 2009, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,187,607
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,423,031
(618,592)
2,081,700
$2,662,152
The accompanying notes are an integral part of these consolidated financial statements.
F-3
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2008
2009
2010
(In thousands, except per share data)
Operating revenues:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,081,898
350,608
30,425
1,462,931
$ 599,287
161,441
21,218
781,946
$1,804,026
217,494
42,360
2,063,880
Operating costs and expenses:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion, amortization and impairment . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . .
Net (gain) loss on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition-related expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating costs and expenses. . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense):
Interest income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other income (expense) . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from continuing operations before income taxes. . . . . .
Income tax expense (benefit):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current
Deferred. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense (benefit). . . . . . . . . . . . . . . . . . . . .
Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . .
Loss from discontinued operations, net of income taxes. . . . . . . . . . .
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
655,678
235,100
7,020
333,493
53,042
(22,812)
(2,000)
2,485
1,262,006
200,925
1,674
(12,772)
927
(10,171)
190,754
357,742
124,100
7,341
289,847
43,935
3,385
3,810
—
830,160
(48,214)
381
(4,148)
426
(3,341)
(51,555)
1,038,327
147,377
12,793
275,990
43,273
(4,163)
4,350
—
1,517,947
545,933
1,553
(630)
502
1,425
547,358
(74,634)
147,490
72,856
117,898
(956)
$ 116,942
(119,038)
101,443
(17,595)
(33,960)
(4,330)
$ (38,290)
128,098
65,392
193,490
353,868
(6,799)
$ 347,069
Basic income (loss) per common share:
Income (loss) from continuing operations . . . . . . . . . . . . . . . . .
Loss from discontinued operations, net of income taxes . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted income (loss) per common share:
Income (loss) from continuing operations . . . . . . . . . . . . . . . . .
Loss from discontinued operations, net of income taxes . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average number of common shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.77
(0.01)
0.76
0.76
(0.01)
0.76
$
$
$
$
$
$
(0.22)
(0.03)
(0.25)
(0.22)
(0.03)
(0.25)
$
$
$
$
$
$
2.29
(0.04)
2.25
2.27
(0.04)
2.23
152,772
153,276
152,069
152,069
153,379
154,358
Cash dividends per common share . . . . . . . . . . . . . . . . . . . . . . . . . .
$
0.20
$
0.20
$
0.60
The accompanying notes are an integral part of these consolidated financial statements.
F-4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Balance, December 31, 2007 . . . . . . . . .
Comprehensive income:
Net income . . . . . . . . . . . . . . . . . . .
Foreign currency translation adjustment,
(net of tax of $8,368) . . . . . . . . . . .
Total comprehensive income . . . . . . . . .
Issuance of restricted stock . . . . . . . . . .
Forfeitures of restricted stock . . . . . . . . .
Exercise of stock options. . . . . . . . . . . .
Stock-based compensation . . . . . . . . . . .
Tax benefit related to stock-based
compensation. . . . . . . . . . . . . . . . . .
Payment of cash dividends. . . . . . . . . . .
Purchase of treasury stock . . . . . . . . . . .
Balance, December 31, 2008 . . . . . . . . .
Comprehensive income (loss):
Net loss . . . . . . . . . . . . . . . . . . . . .
Foreign currency translation adjustment,
(net of tax of $5,347) . . . . . . . . . . .
Total comprehensive loss . . . . . . . . . . . .
Issuance of restricted stock . . . . . . . . . .
Vesting of restricted stock units . . . . . . .
Forfeitures of restricted stock . . . . . . . . .
Exercise of stock options. . . . . . . . . . . .
Stock-based compensation . . . . . . . . . . .
Tax expense related to stock-based
compensation. . . . . . . . . . . . . . . . . .
Payment of cash dividends. . . . . . . . . . .
Purchase of treasury stock . . . . . . . . . . .
Balance, December 31, 2009 . . . . . . . . .
Comprehensive income:
Net income . . . . . . . . . . . . . . . . . . .
Foreign currency translation adjustment,
(net of tax of $2,814) . . . . . . . . . . .
Total comprehensive income . . . . . . . . .
Issuance of restricted stock . . . . . . . . . .
Vesting of restricted stock units . . . . . . .
Forfeitures of restricted stock . . . . . . . . .
Exercise of stock options. . . . . . . . . . . .
Stock-based compensation . . . . . . . . . . .
Tax expense related to stock-based
compensation. . . . . . . . . . . . . . . . . .
Payment of cash dividends. . . . . . . . . . .
Purchase of treasury stock . . . . . . . . . . .
Common Stock
Number of
Shares
Amount
Additional
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income
Treasury
Stock
Total
(In thousands)
177,386
$1,773
$703,581
$1,716,620
$ 20,207
$(546,151) $1,896,030
—
—
—
577
(75)
2,304
—
—
—
—
—
—
—
6
(1)
23
—
—
—
—
—
—
—
(6)
1
25,525
20,131
16,280
—
—
347,069
—
347,069
—
—
—
—
—
(92,865)
—
—
(14,433)
(14,433)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(70,818)
347,069
(14,433)
332,636
—
—
25,548
20,131
16,280
(92,865)
(70,818)
180,192
1,801
765,512
1,970,824
5,774
(616,969)
2,126,942
—
—
—
604
6
(56)
83
—
—
—
—
—
—
—
6
—
—
1
—
—
—
—
—
—
—
(6)
—
—
568
18,565
(3,004)
—
—
(38,290)
—
(38,290)
—
—
—
—
—
—
(30,681)
—
—
9,222
9,222
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,623)
(38,290)
9,222
(29,068)
—
—
—
569
18,565
(3,004)
(30,681)
(1,623)
180,829
1,808
781,635
1,901,853
14,996
(618,592)
2,081,700
—
—
—
700
7
(59)
61
—
—
—
—
—
—
—
7
—
(1)
1
—
—
—
—
—
—
—
(7)
—
1
524
16,779
(2,291)
—
—
116,942
—
116,942
—
—
—
—
—
—
(30,796)
—
—
6,601
6,601
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
116,942
6,601
123,543
—
—
—
525
16,779
—
—
(1,853)
(2,291)
(30,796)
(1,853)
Balance, December 31, 2010 . . . . . . . . .
181,538
$1,815
$796,641
$1,987,999
$ 21,597
$(620,445) $2,187,607
The accompanying notes are an integral part of these consolidated financial statements.
F-5
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion, amortization and impairment . . . . . . . . . .
Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry holes and abandonments . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . .
Net (gain) loss on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . .
Tax expense related to stock-based compensation . . . . . . . . . . . . .
Changes in operating assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes receivable/payable . . . . . . . . . . . . . . . . . . . . . . . .
Inventory and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities of discontinued
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities:
Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of property and equipment . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by (used in) investing activities of discontinued
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities:
Purchases of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax benefit related to stock-based compensation . . . . . . . . . . . . . . . .
Proceeds from long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayment of long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from borrowings under revolving credit facility . . . . . . . . .
Repayment of borrowings under revolving credit facility . . . . . . . . .
Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by (used in) financing activities . . . . . . . . . . . .
Effect of foreign exchange rate changes on cash . . . . . . . . . . . . . .
Net increase (decrease) in cash and cash equivalents . . . . . . . . .
Cash and cash equivalents at beginning of year . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at end of year . . . . . . . . . . . . . . . . . . . . . . .
Supplemental disclosure of cash flow information:
Net cash (paid) received during the year for:
Interest expense, net of capitalized interest of $2,288 in 2010,
$0 in 2009 and $0 in 2008 . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash investing and financing activities:
Net increase (decrease) in payables for purchases of property
and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (increase) decrease in deposits on equipment purchases. . . .
2010
Year Ended December 31,
2009
(In thousands)
2008
$ 116,942
$ (38,290)
$ 347,069
333,493
(2,000)
519
147,490
16,779
(22,812)
(2,291)
(178,444)
43,522
(8,772)
49,576
18,072
3,234
10,390
525,698
(238,022)
(738,090)
29,409
42,638
(904,065)
289,847
3,810
129
101,443
18,214
3,385
(3,004)
213,813
(108,664)
14,178
(52,673)
(21,178)
(92)
32,759
453,677
—
(452,646)
3,359
(54)
(449,341)
(1,853)
(30,796)
—
400,000
(1,250)
200,000
(200,000)
(10,779)
525
355,847
255
(22,265)
49,877
$ 27,612
(1,623)
(30,681)
—
—
—
—
—
(6,169)
569
(37,904)
2,222
(31,346)
81,223
$ 49,877
275,990
4,350
1,617
65,392
19,688
(4,163)
—
(30,777)
(11,258)
2,498
6,486
(4,474)
1,242
1,344
675,004
—
(445,426)
11,436
(3,286)
(437,276)
(70,818)
(92,865)
16,280
—
—
—
(50,000)
—
25,548
(171,855)
(2,084)
63,789
17,434
$ 81,223
$
— $
115,666
(1,804)
14,029
$
(323)
(126,331)
$ 29,188
(50,170)
$ (25,110)
43,029
$
(3,590)
(42,293)
The accompanying notes are an integral part of these consolidated financial statements.
F-6
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”), provides onshore contract drilling services to major and
independent oil and natural gas operators primarily 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 Texas and 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 other 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 deter-
mination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract
drilling arrangements and the 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 as
revenue reimbursements received from third parties for out-of-pocket expenses and accounts for those
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, 2010, 2009 and 2008 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 consist primarily of sand and chemical products to be used in conjunction with the
Company’s pressure pumping activities. The inventories are stated at the lower of cost or market, determined by the
first-in, first-out method.
F-7
Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depre-
ciation is provided on the straight-line method over the estimated useful lives. The method of depreciation does not
change whenever equipment becomes idle. The estimated useful lives, in years, are shown below:
Useful Lives
Drilling rigs and other equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2-15
15-20
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 economic viability of the respective projects. If no
progress has been made in assessing the reserves and economic viability of a project after one year following the
completion of drilling, the Company considers the well costs 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 for each respective field.
The Company reviews its proved oil and natural gas properties for impairment whenever 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 cash flow estimates are 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 net book value and discounted cash flow. The
discounted cash flow estimates used in measuring impairment are based on management’s expectations of future
commodity prices over the life of the respective field. The Company reviews unproved oil and natural gas properties
quarterly to assess potential impairment. The Company’s impairment assessment is made on a lease-by-lease basis
and considers factors such as management’s intent to drill, lease terms and abandonment of an area. If an unproved
property is determined to be impaired, the related property costs 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 as of December 31, or on an interim basis if events or
circumstances indicate that the fair value of goodwill may have decreased below its carrying value.
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
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 year ended December 31, 2008 have been adjusted retrospectively to conform with this accounting standard.
F-8
The impact of this retrospective application to the year ended December 31, 2008 was to reduce Basic EPS and
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, loss from discontinued operations per share and net income (loss) per share for the years ended December 31,
2010, 2009 and 2008, as well as potentially dilutive securities excluded from the weighted average number of
diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per
share amounts):
2010
2009
2008
BASIC EPS:
Income (loss) from continuing operations . . . . . . . . . . . . . . . . . $117,898
$ (33,960)
$353,868
Adjust for (income) loss attributed to holders of non-vested
restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(884)
313
(3,279)
Income (loss) from continuing operations attributed to common
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $117,014
$ (33,647)
$350,589
Loss from discontinued operations, net . . . . . . . . . . . . . . . . . . . $
(956)
$ (4,330)
$ (6,799)
Adjust for loss attributed to holders of non-vested restricted
stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
38
64
Loss from discontinued operations attributed to common
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(949)
$ (4,292)
$ (6,735)
Weighted average number of common shares outstanding,
excluding non-vested shares of restricted stock . . . . . . . . . . .
152,772
152,069
153,379
Basic income (loss) from continuing operations per common
share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Basic loss from discontinued operations per common share . . . . $
Basic net income (loss) per common share . . . . . . . . . . . . . . . . $
0.77
(0.01)
0.76
$
$
$
(0.22)
(0.03)
(0.25)
$
$
$
2.29
(0.04)
2.25
F-9
2010
2009
2008
DILUTED EPS:
Income (loss) from continuing operations attributed to common
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $117,014
Add incremental earnings related to potential common
shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
$ (33,647)
$350,589
—
15
Adjusted income (loss) from continuing operations attributed to
common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $117,014
$ (33,647)
$350,604
Weighted average number of common shares outstanding,
excluding non-vested shares of restricted stock . . . . . . . . . . .
Add dilutive effect of potential common shares . . . . . . . . . . .
152,772
504
152,069
—
153,379
979
Weighted average number of diluted common shares
outstanding. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
153,276
152,069
154,358
Diluted income (loss) from continuing operations per common
share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted loss from discontinued operations per common share . . $
Diluted net income (loss) per common share . . . . . . . . . . . . . . . $
0.76
(0.01)
0.76
$
$
$
Potentially dilutive securities excluded as anti-dilutive . . . . . . . .
4,164
(0.22)
(0.03)
(0.25)
8,090
$
$
$
2.27
(0.04)
2.23
2,455
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’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.
Recently Issued Accounting Standards — 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. Prior to 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 October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-
deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined
unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement
consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective
F-10
and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a
multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements
will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy
for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The
selling price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-
specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence
nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements
entered into in fiscal years beginning on or after June 15, 2010 and became effective for the Company on January 1,
2011. The adoption of this standard is not expected to have a material impact on the Company’s consolidated
financial position, results of operations or cash flows.
In December 2010, the FASB issued an accounting standard update that addresses the disclosure of supple-
mentary pro forma information for business combinations. This update clarifies that when public entities are
required to disclose pro forma information for business combinations that occurred in the current reporting period,
the pro forma information should be presented as if the business combination occurred as of the beginning of the
previous fiscal year when comparative financial statements are presented. This update is effective prospectively for
business combinations for which the acquisition date is on or after the beginning of the first annual reporting period
beginning on or after December 15, 2010. Early adoption is permitted. The Company elected to early adopt this
update and this early adoption did not have an impact on the Company’s consolidated financial position, results of
operations or cash flows.
Reclassifications — Certain reclassifications have been made to the 2009 and 2008 consolidated financial
statements in order for them to conform with the 2010 presentation. These reclassifications had no significant
impact on the Company’s financial position, results of operations or cash flows.
2. Discontinued Operations
On January 27, 2011, the stock of the Company’s electric wireline subsidiary, Universal Wireline, Inc., was
sold in a cash transaction for $25.5 million. Except for inventory, the working capital of Universal Wireline, Inc. was
excluded from the sale and retained by a subsidiary of the Company. Universal Wireline, Inc. was formed in 2010 to
acquire the electric wireline business of Key Energy Services, Inc., as discussed in Note 3. The results of operations
of this business have been presented as results of discontinued operations in these consolidated financial statements.
As of December 31, 2010, the assets to be disposed of were classified as held for sale and are presented separately
within current assets under the caption “Assets held for sale” in the consolidated balance sheet. Upon being
classified as held for sale, the assets to be disposed of were recorded at fair value less estimated costs to sell resulting
in a charge of $2.2 million. Due to the fact that the carrying value of the assets had been adjusted to net realizable
value, no significant additional gain or loss was recognized in connection with the sale.
On January 20, 2010, the Company exited the drilling and completion fluids 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 $42.6 million. Upon the Company’s exit from the
drilling and completion fluids 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 were considered held for sale and were presented separately
within current assets under the caption “Assets held for sale” in the consolidated balance sheet. Upon being
classified as held for sale, the assets to be disposed of were adjusted to fair value less estimated costs to sell resulting
in an impairment loss of $1.9 million. Due to the fact that the carrying value of the assets had been adjusted to net
realizable value, no significant additional gain or loss was recognized in connection with the sale in 2010.
F-11
Summarized operating results from discontinued operations for the years ended December 31, 2010, 2009 and
2008 are shown below (in thousands):
2010
2009
2008
Drilling and completion fluids revenues . . . . . . . . . . . . . . . . . . . .
Electric wireline revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 3,737
5,712
$79,786
—
$145,246
—
Operating revenues from discontinued operations . . . . . . . . . . . . .
$ 9,449
$79,786
$145,246
Loss before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(1,499)
543
$ (6,538)
2,208
$ (4,410)
(2,389)
Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . .
$ (956)
$ (4,330)
$ (6,799)
The loss before income taxes in 2008 includes approximately $10.0 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, 2010 and 2009 are shown below (in thousands):
2010
2009
Assets held for sale:
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unbilled accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . .
Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . .
Reserve to reduce disposal group to fair value less costs to sell
$
756
—
—
24,769
(2,155)
$28,620
6,587
324
8,793
(1,900)
Total assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$23,370
$42,424
3. Acquisitions
On October 1, 2010, two subsidiaries of the Company, Universal Pressure Pumping, Inc. and Universal
Wireline, Inc., completed the acquisition of certain assets from Key Energy Pressure Pumping Services, LLC and
Key Electric Wireline Services, LLC relating to the businesses of providing pressure pumping services and electric
wireline services to participants in the oil and natural gas industry. This acquisition expanded the Company’s
pressure pumping operations to additional markets primarily in Texas. The aggregate purchase price was
$241 million consisting of a cash payment of $238 million at closing funded through a combination of cash on
hand and a $200 million draw on the Company’s revolving credit facility, a subsequent cash payment based on the
value of closing inventory of approximately $1.2 million to be made in the first quarter of 2011 and the assumption
of liabilities of approximately $2.1 million. The purchase price was allocated to the tangible and identifiable
intangible assets acquired and liabilities assumed based on fair value. The tangible assets acquired include property
and equipment, inventories of sand and chemicals on hand and repair and maintenance supplies on hand. The
identifiable intangible assets acquired include an agreement by the seller to not compete for a period of three years
and the customer relationships in place at the time of the acquisition. The liabilities assumed arose from pricing
agreements in place with certain customers that had pricing below current market rates. A related deferred tax asset
was recognized to reflect the temporary difference associated with these below-market pricing arrangements. The
excess of the purchase price over the fair values of the tangible assets, the identifiable intangible assets and deferred
F-12
tax asset, net of the liabilities assumed is recorded as goodwill and was attributed to the pressure pumping business
acquired. A summary of the purchase price allocation follows (in thousands):
Sand and chemical inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-compete agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax asset. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Below-market pricing agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,848
312
154,359
1,400
25,500
8,514
67,575
(23,200)
Total purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $241,308
In addition to the purchase price, acquisition-related expenses associated with this transaction of approxi-
mately $2.5 million were incurred by the Company and are presented in the consolidated statement of operations
under the caption “acquisition-related expenses” for the year ended December 31, 2010. These expenses include
certain legal and other professional fees directly related to the transaction, fees incurred in connection with title
transfers of the acquired equipment and transition costs related to information technology.
As discussed in Note 2, the electric wireline business was classified as held for sale at December 31, 2010 and
was subsequently sold on January 27, 2011. The results of operations of the wireline business from the date of
acquisition included revenue of $5.7 million and a pre-tax operating loss of $1.5 million (including a charge of
approximately $2.2 million incurred to reduce the carrying value of the disposal group to its net realizable value)
which is included in loss from discontinued operations for the year ended December 31, 2010. Results of operations of
the acquired pressure pumping business are included in the Company’s consolidated results of operations from the
date of acquisition. Revenues of $84.7 million and income from operations of $22.8 million from the acquired pressure
pumping business are included in the consolidated statement of operations for the year ended December 31, 2010.
The following represents pro-forma unaudited financial information for the years ended December 31, 2010
and 2009 as if the acquisition had been completed on January 1, 2009 (in thousands, except per share amounts):
2010
2009
(Unaudited)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic income (loss) from continuing operations per common share . . . . . .
Basic net income (loss) per common share . . . . . . . . . . . . . . . . . . . . . . . .
Diluted income (loss) from continuing operations per common share . . . . .
Diluted net income (loss) per common share . . . . . . . . . . . . . . . . . . . . . . .
$1,660,635
$ 127,257
$ 126,301
0.83
$
0.83
$
0.82
$
0.82
$
$905,168
$ (46,807)
$ (51,137)
(0.33)
$
(0.36)
$
(0.33)
$
(0.36)
$
F-13
4. Property and Equipment
Property and equipment consisted of the following at December 31, 2010 and 2009 (in thousands):
2010
2009
Equipment
Oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,972,891
110,749
61,425
11,074
$ 3,230,737
93,354
56,563
9,795
Less accumulated depreciation and depletion . . . . . . . . . . . . . . . . . . . .
4,156,139
(1,535,239)
3,390,449
(1,280,047)
Property and equipment, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,620,900
$ 2,110,402
Depreciation, depletion, amortization and impairment — The following table summarizes depreciation,
depletion, amortization and impairment expense related to property and equipment and intangible assets for
2010, 2009 and 2008 (in millions):
2010
2009
2008
Depreciation and impairment expense . . . . . . . . . . . . . . . . . . . . . . . . . $322.3
1.0
Amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.2
Depletion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$280.6
—
9.2
$264.5
—
11.5
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $333.5
$289.8
$276.0
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 and a significant decline in oil and natural gas commodity prices,
the Company deemed it necessary to assess the recoverability of long-lived assets within its contract drilling
segment in 2008. Due to a continued decrease in the operating levels within its contract drilling business segment
through the first three quarters of 2009, the Company again deemed it necessary to perform an impairment
assessment of long-lived assets in its contract drilling segment in 2009. In light of the recent favorable trends in rig
utilization and revenue per operating day experienced by the Company and its peers, management concluded that no
triggering event had occurred in 2010 with respect to its contract drilling segment. 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 in 2010, 2009 or 2008.
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 2010, 2009 and 2008. 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 $792,000, $3.7 million and $4.4 million in 2010, 2009 and 2008, respectively, related to its
oil and natural gas properties. The Company determined the fair value of the impaired assets using internally
developed unobservable inputs including future pricing and reserves (level 3 inputs in the fair value hierarchy of fair
value accounting).
During 2010, 2009 and 2008, in connection with its long-term planning process, the Company evaluated its
then-current fleet of marketable drilling rigs and identified four, 23 and 22 rigs, respectively, that it determined
F-14
would no longer be marketed as rigs. 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 yards to be used as
spare equipment. The remaining components of these rigs were impaired and the associated net book value of
$4.2 million in 2010, $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 impaired components were estimated to have no fair value.
During 2010, the Company sold certain rights to explore and develop zones deeper than depths that it generally
targets for certain of the oil and natural gas properties in which it has working interests. The proceeds from this sale
were approximately $22.3 million and the sale resulted in a gain on disposal of $20.1 million.
5. Goodwill and Intangible Assets
Goodwill — Goodwill by operating segment as of December 31, 2010 and 2009 and changes for the years then
ended are as follows (in thousands):
2010
2009
Contract Drilling:
Balance as of January 1:
Goodwill
Accumulated impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 86,234
—
Changes to goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31:
Goodwill
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure Pumping:
Balance as of January 1:
Goodwill
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86,234
—
86,234
—
86,234
—
—
Goodwill recorded in connection with business combination . . . . . . . . . . . . . .
67,575
Balance as of December 31:
Goodwill
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
67,575
—
67,575
$86,234
—
86,234
—
86,234
—
86,234
—
—
—
—
—
—
Total goodwill as of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $153,809
$86,234
Goodwill recorded in connection with a business combination in 2010 was a result of the Company’s
acquisition of the pressure pumping business of Key Energy Services, Inc. on October 1, 2010, as discussed further
in Note 3. Approximately $53.2 million of this goodwill is expected to be deductible for tax purposes.
Goodwill is evaluated at least annually on December 31 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.
The Company performed its annual goodwill impairment assessment as of December 31, 2009 related to the
$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
F-15
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.
The Company performed its annual goodwill impairment assessment as of December 31, 2010. In completing its
first step of the analysis, the Company estimated its enterprise value based on the market capitalization of the
Company as determined by reference to the closing price of the Company’s common stock during the fifteen days
before and after year end. The enterprise value was allocated to the Company’s reporting units and it was determined
that the fair values of the Company’s reporting units were in excess of their carrying value. As a result, the Company
concluded that no impairment of goodwill was indicated as of December 31, 2010.
In the event that market conditions weaken, the Company may determine additional impairments of goodwill
in its contract drilling or pressure pumping reporting units in the future, and such impairment could be material.
Intangible Assets — Intangible assets were recorded in the pressure pumping operating segment in connection
with the fourth quarter 2010 acquisition of the assets of the pressure pumping business discussed in Note 3. As a
result of the purchase price allocation, the Company recorded intangible assets related to a non-compete agreement
and the customer relationships acquired. These intangible assets were recorded at fair value on the date of
acquisition.
The non-compete agreement has a term of three years from October 1, 2010. The value of this agreement was
estimated using a with and without scenario where cash flows were projected through the term of the agreement
assuming the agreement is in place and compared to cash flows assuming the non-compete agreement was not in
place. The intangible asset associated with the non-compete agreement is being amortized on a straight-line basis
over the three-year term of the agreement. Amortization expense of $116,000 was recorded in the year ended
December 31, 2010 associated with the non-compete agreement.
The value of the customer relationships was estimated using a multi-period excess earnings model to
determine the present value of the projected cash flows associated with the customers in place at the time of
the acquisition and taking into account a contributory asset charge. The resulting intangible asset is being amortized
on a straight-line basis over seven years. Amortization expense of $910,000 was recorded in the year ended
December 31, 2010 associated with customer relationships.
The following table sets forth the activity with respect to intangible assets for the year ended December 31,
2010 (in thousands):
Intangible assets at January 1, 2010 . . . . . . . . . . . . . . . . . . .
Intangible assets recognized at fair value in business
combination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated amortization at December 31, 2010 . . . . . . . . .
Non-compete
Customer
Relationships
Total
$ —
$ —
$ —
1,400
(116)
(116)
25,500
(910)
(910)
26,900
(1,026)
(1,026)
Intangible assets, net at December 31, 2010 . . . . . . . . . . . . .
$1,284
$24,590
$25,874
F-16
6. Accrued Expenses
Accrued expenses consisted of the following at December 31, 2010 and 2009 (in thousands):
2010
2009
Salaries, wages, payroll taxes and benefits . . . . . . . . . . . . . . . . . . . . . . . . . . $ 39,766
63,011
Workers’ compensation liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,782
Sales, use and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,648
Insurance, other than workers’ compensation . . . . . . . . . . . . . . . . . . . . . . . .
10,220
Deferred revenue — current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14,888
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 15,657
65,825
11,090
12,498
—
3,680
$147,315
$108,750
Deferred revenue was recorded in 2010 in the purchase price allocation associated with the Company’s
acquisition of a pressure pumping business as discussed in Note 3. The deferred revenue relates to out-of-market
pricing agreements that were in place at the acquired business at the time of the acquisition. The deferred revenue
will be recognized as pressure pumping revenue over the remaining term of the pricing agreements. Deferred
revenue of approximately $6.1 million was recognized in the year ended December 31, 2010 related to these pricing
agreements.
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” in the liabilities section of
the consolidated balance sheet. The following table describes the changes to the Company’s asset retirement
obligations during 2010 and 2009 (in thousands):
Balance at beginning of year. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,955
335
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(339)
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
112
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Revision in estimated costs of plugging oil and natural gas wells . . . . . . . . . . . . .
$3,047
157
(354)
118
(13)
Asset retirement obligation at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,063
$2,955
2010
2009
8. Long Term Debt
In March 2009, the Company entered into an unsecured revolving credit facility (the “2009 Credit Facility”)
with a maximum borrowing capacity of $240 million. The Company incurred debt issuance costs of approximately
$6.2 million during 2009 in connection with the 2009 Credit Facility. These costs were being amortized to interest
expense over the contractual term of the 2009 Credit Facility.
On July 2, 2010, the Company entered into a 364-Day Credit Agreement (the “364-Day Credit Agreement”)
among the Company, as borrower, and Wells Fargo Bank, N.A., as administrative agent and lender. The 364-Day
Credit Agreement was a committed senior unsecured single draw term loan credit facility that permitted a
borrowing of up to $250 million, provided that the loan must have been drawn no later than September 30, 2010 or,
if an additional fee was paid, October 30, 2010. The maturity date under the 364-Day Credit Agreement was
364 days after the date on which the closing conditions under the 364-Day Credit Agreement were met. This facility
was not drawn as of September 30, 2010 and it expired at that time.
On August 19, 2010, the Company entered into a Credit Agreement (the “2010 Credit Agreement”) among the
Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and
lender, and each of the other letter of credit issuer and lender parties thereto. The 2010 Credit Agreement is a
F-17
committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The 2010
Credit Agreement replaced the 2009 Credit Facility.
The revolving credit facility permits aggregate borrowings of up to $400 million and contains a letter of credit
facility that is limited to $150 million and a swing line facility that is limited to $40 million. Subject to customary
conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit
facility be increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for
the revolving facility is August 19, 2013.
The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan
facility is payable in quarterly principal installments commencing November 19, 2010, and the installment amounts
vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the
original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal
amount for the next subsequent three quarterly installments and the remainder is due at maturity. The maturity date
for the term loan facility is August 19, 2014.
Loans under the 2010 Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR
rate or base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin
on base rate loans varies from 1.75% to 2.75%, in each case determined based upon the Company’s debt to
capitalization ratio. As of December 31, 2010, the applicable margin on LIBOR rate loans was 2.75% and the
applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by the Company equal to the
applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of
credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from
0.50% to 0.75% based upon the Company’s debt to capitalization ratio and was 0.50% as of December 31, 2010.
Each domestic subsidiary of the Company other than any immaterial subsidiary has unconditionally guar-
anteed all existing and future indebtedness and liabilities of the Company and the other guarantors arising under the
2010 Credit Agreement and other loan documents. Such guarantees also cover obligations of the Company and any
subsidiary of the Company arising under any interest rate swap contract with any person while such person is a
lender or affiliate of a lender under the 2010 Credit Agreement.
The 2010 Credit Agreement contains customary representations, warranties, indemnities and affirmative and
negative covenants. The 2010 Credit Agreement also requires compliance with two financial covenants. The
Company must not permit its debt to capitalization ratio to exceed 45% at any time. The 2010 Credit Agreement
generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum
of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the
most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of
a fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit Agreement generally defines the interest coverage ratio
as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal
quarters to interest charges for the same period. 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, 2010, the Company had $98.8 million principal amount outstanding under the term loan
facility at an interest rate of 3.125% and no borrowings outstanding under the revolving credit facility. The
Company had $41.2 million in letters of credit outstanding at December 31, 2010 and, as a result, had available
borrowing capacity of approximately $359 million at that date.
Senior Notes — On October 5, 2010, the Company completed the issuance and sale of $300 million in
aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Notes”) in a private
placement. A portion of the proceeds from the Notes was used to repay a $200 million borrowing on the Company’s
revolving credit facility, which had been drawn to fund a portion of the acquisition that closed on October 1, 2010 as
discussed in Note 3. The Notes are senior unsecured obligations of the Company which rank equally in right of
payment with all other unsubordinated indebtedness of the Company. The Notes are guaranteed on a senior
unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries.
The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal amount of the
Notes. The Company will pay interest on the Notes on April 5 and October 5 of each year commencing on April 5,
F-18
2011. The Notes will mature on October 5, 2020. The Notes are prepayable at the Company’s option, in whole or in
part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the
aggregate principal amount of the Notes then outstanding, at any time and from time to time at 100% of the principal
amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as
specified in the note purchase agreement. The Company must offer to prepay the Notes upon the occurrence of any
change of control. In addition, the Company must offer to prepay the Notes upon the occurrence of certain asset
dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is
accepted, the purchase price of each prepaid Note is 100% of the principal amount thereof, plus accrued and unpaid
interest thereon to the prepayment date.
The note purchase agreement requires compliance with two financial covenants. The Company must not
permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the
debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness
plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended
fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be
less than 2.50 to 1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the
four prior quarters of EBITDA to interest charges for that same period. The Company does not expect that the
restrictions and covenants will impair its ability to operate or react to opportunities that might arise.
Events of default under the note purchase agreement include failure to pay principal or interest when due,
failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a
threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a
change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing,
then holders of a majority in principal amount of the Notes have the right to declare all the Notes then-outstanding to
be immediately due and payable. In addition, if the Company defaults in payments on any Note, then until such
defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due and payable.
During the year ended December 31, 2010, the Company incurred approximately $10.8 million in debt
issuance costs in connection with the 2010 Credit Agreement and the Senior Notes discussed above. These costs
were deferred and will be recognized as interest expense over the term of the underlying debt. For the year ended
December 31, 2010, interest expense related to the amortization of debt issuance costs for the 2010 Credit
Agreement and the Senior Notes was approximately $1.1 million.
Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of
December 31, 2010 (in thousands):
Year ending December 31,
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,250
10,000
12,500
70,000
—
300,000
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $398,750
9. Commitments, Contingencies and Other Matters
Commitments — As of December 31, 2010, the Company maintained letters of credit in the aggregate amount
of $41.2 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, 2010, no amounts
had been drawn under the letters of credit.
As of December 31, 2010, the Company had commitments to purchase approximately $267 million of major
equipment.
F-19
Contingencies — The Company’s contract services operations are subject to inherent risks, including blow-
outs, 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, subject to a $2.0 million self-insured retention,
general liability insurance coverage, 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, 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 equipment. However, it does not cover
the full replacement cost of the equipment 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.
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:
(cid:129) 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);
(cid:129) 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
(cid:129) 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.
F-20
10. Stockholders’ Equity
Cash Dividends — The Company paid cash dividends during the years ended December 31, 2008, 2009 and
2010 as follows:
Per Share
Total
(in thousands)
2008:
Paid on March 28, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on June 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on September 29, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on December 29, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009:
Paid on March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on December 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010:
Paid on March 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on June 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on September 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Paid on December 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$0.12
0.16
0.16
0.16
$0.60
$0.05
0.05
0.05
0.05
$0.20
$0.05
0.05
0.05
0.05
$0.20
$18,493
25,011
24,803
24,558
$92,865
$ 7,655
7,675
7,675
7,676
$30,681
$ 7,677
7,706
7,704
7,709
$30,796
On February 2, 2011, 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, 2011 to holders of record as of March 15, 2011. 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, 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.
During the year ended December 31, 2010, the Company purchased 8,743 shares of its common stock under the
program at a cost of approximately $123,000. As of December 31, 2010, 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.
The Company purchased 117,083, 114,983 and 152,235 shares of treasury stock from employees during 2010,
2009 and 2008, 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 $1.7 million, $1.5 million and $4.5 million in 2010, 2009 and 2008,
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.
F-21
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. Share-based awards
consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included
service and, in certain cases, performance conditions. The Company’s share-based awards also include both cash-
settled and share-settled performance unit awards. Cash-settled performance unit awards are accounted for as
liability awards. Share-settled performance unit awards are accounted for as equity awards. The Company issues
shares of common stock when vested stock options are exercised, when restricted stock is granted and when
restricted stock units and share-settled performance unit awards 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 2010, the Company amended the 2005 Plan to, among other
things, increase the total number of shares authorized for grant from 10,250,000 to 15,250,000. The Company’s
share-based compensation plans at December 31, 2010 follow:
Plan Name
Shares
Authorized
for Grant
Awards
Outstanding
Shares
Available
for Grant
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan,
as amended . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,250,000
5,830,135
5,763,314
Patterson-UTI Energy, Inc. Amended and Restated 1997
Long-Term Incentive Plan, as amended (“1997 Plan”) . . .
— 2,843,300
Amended and Restated Patterson-UTI Energy, Inc. 2001
Long-Term Incentive Plan (“2001 Plan”) . . . . . . . . . . . . .
—
168,552
—
—
A summary of the 2005 Plan follows:
(cid:129) The Compensation Committee of the Board of Directors administers the plan.
(cid:129) All employees including officers and directors are eligible for awards.
(cid:129) The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one
year for non-employee directors and three to four years for employees.
(cid:129) The Compensation Committee sets the term of awards and no option term can exceed 10 years.
(cid:129) 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.
(cid:129) The plan provides for awards of incentive stock options, non-incentive stock options, tandem and free-
standing stock appreciation rights, restricted stock awards, other stock unit awards, performance share
awards, performance unit awards and dividend equivalents. As of December 31, 2010, 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.
Stock Options — The Company estimates the grant date fair values of stock options using the Black-Scholes-
Merton valuation model. 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.
F-22
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 yields. Weighted-average
assumptions used to estimate grant date fair values for stock options granted in the years ended December 31,
2010, 2009 and 2008 follow:
Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected term (in years) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
45.98% 49.90% 37.04%
5.00
4.00
1.35% 1.67% 2.27%
2.47% 1.67% 2.91%
4.17
2010
2009
2008
Stock option activity for the year ended December 31, 2010 follows:
Outstanding at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares
6,841,770
1,016,250
(60,918)
(10,000)
(77,000)
Outstanding at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,710,102
Exercisable at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,095,018
Weighted-average
exercise price
$20.17
$14.85
$ 8.61
$13.17
$19.46
$19.58
$20.81
Options outstanding at December 31, 2010 have an aggregate intrinsic value of approximately $30.0 million
and a weighted-average remaining contractual term of 5.6 years. Options exercisable at December 31, 2010 have an
aggregate intrinsic value of approximately $18.7 million and a weighted-average remaining contractual term of
4.8 years. Additional information with respect to options granted, vested and exercised during the years ended
December 31, 2010, 2009 and 2008 follows:
Weighted-average grant date fair value of stock options granted (per
share) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5.69
$ 4.71
$ 7.20
Grant date fair value of stock options vested during the year (in
thousands) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,553
Aggregate intrinsic value of stock options exercised (in thousands) . . . $ 523
$6,973
$ 510
$ 6,761
$45,240
2010
2009
2008
As of December 31, 2010, options to purchase 1,615,084 shares were outstanding and not vested. All of these
non-vested options are expected to ultimately vest. Additional information as of December 31, 2010 with respect to
these non-vested options follows:
Aggregate intrinsic value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average remaining contractual term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average remaining expected term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average remaining vesting period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized compensation cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11.3 million
8.88 years
3.56 years
1.88 years
$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. The
Company uses the straight-line method to recognize periodic compensation cost over the vesting period.
F-23
Restricted stock activity for the year ended December 31, 2010 follows:
Non-vested restricted stock outstanding at beginning of year . . . . . . . . . . . . 1,231,901
699,825
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(758,394)
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(59,281)
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested restricted stock outstanding at end of year . . . . . . . . . . . . . . . . 1,114,051
Shares
Weighted-
average
Grant Date
Fair Value
$21.67
$14.68
$23.48
$21.63
$16.05
As of December 31, 2010, approximately 976,000 shares of non-vested restricted stock outstanding are
expected to vest. Additional information as of December 31, 2010 with respect to these non-vested shares follows:
Aggregate intrinsic value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average remaining vesting period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized compensation cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$21.0 million
1.90 years
$12.2 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, 2010 follows:
Non-vested restricted stock units outstanding at beginning of year . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares
16,167
9,000
(7,333)
—
Non-vested restricted stock units outstanding at end of year. . . . . . . . . . . . . . .
17,834
Weighted
Average
Grant Date
Fair Value
$26.81
$13.81
$28.08
$ —
$19.73
Performance Unit Awards. On April 28, 2009, the Company granted cash-settled 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, but can extend through March 31, 2014 in certain circumstances. 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 of the Board of
Directors. These goals are considered to be market conditions under the relevant accounting standards and the
market conditions are factored into the determination of the fair value of the performance units. 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. Because the 2009
Performance Units are to be settled in cash at the end of the performance period, they are accounted for as liability
awards and the Company’s pro-rated obligation is measured at estimated fair value at the end of each reporting
period using a Monte Carlo simulation model. As of December 31, 2010 this pro-rated obligation was approx-
imately $2.3 million and is included in the caption “other” in the liabilities section of the consolidated balance sheet.
Compensation expense associated with the 2009 Performance Units was approximately $1.5 million and $859,000
for the years ended December 31,2010 and 2009, respectively.
F-24
On April 27, 2010, the Company granted stock-settled performance unit awards to certain executive officers
(the “2010 Performance Units”). The 2010 Performance Units provide for those executive officers to receive a grant
of shares of stock upon the achievement of certain performance goals established by the Company during a
specified period. The performance period for the 2010 Performance Units is the period from April 1, 2010 through
March 31, 2013, but can extend through March 31, 2015 in certain circumstances. The performance goals for the
2010 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 of the Board of Directors.
These goals are considered to be market conditions under the relevant accounting standards and the market
conditions are factored into the determination of the fair value of the performance units. Generally, the recipients
will receive a base number of shares 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 grant
of shares when achievement is between the 25th and 75th percentile will be determined on a pro-rata basis. The total
base number of shares with respect to the 2010 Performance Units is 89,375 shares. Because the 2010 Performance
Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of
grant. The fair value of the 2010 Performance Units as of the date of grant was approximately $3.1 million using a
Monte Carlo simulation model. This amount will be recognized on a straight-line basis over the performance
period. Compensation expense associated with the 2010 Performance Units was approximately $779,000 for the
year ended December 31, 2010.
Dividends on Equity Awards — Non-forfeitable cash dividends and dividend equivalents paid on equity
awards are recognized as follows:
(cid:129) Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards
expected to vest.
(cid:129) 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.
(cid:129) Dividend equivalents are recognized as additional compensation cost for restricted stock units.
12. Leases
The Company incurred rent expense of $18.1 million, $11.9 million and $31.5 million for the years 2010, 2009
and 2008, respectively. Rent expense is primarily related to short-term equipment rentals that are generally passed
through to customers. The Company’s obligations under non-cancelable operating lease agreements are not
material to its operations or cash flows.
F-25
13.
Income Taxes
Components of the income tax provision applicable to Federal, state and foreign income taxes for the years
ended December 31, 2010, 2009 and 2008 are as follows (in thousands):
2010
2009
2008
Federal income tax expense (benefit):
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (77,310)
145,198
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(117,493)
103,574
$117,367
57,879
State income tax expense (benefit):
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign income tax expense (benefit):
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
67,888
(13,919)
175,246
19
3,246
3,265
2,657
(954)
1,703
(1,883)
(1,875)
(3,758)
338
(256)
82
6,475
7,070
13,545
4,256
443
4,699
Total income tax expense (benefit):
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(74,634)
147,490
(119,038)
101,443
128,098
65,392
Total income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . $ 72,856
$ (17,595)
$193,490
The difference between the statutory Federal income tax rate and the effective income tax rate for the years
ended December 31, 2010, 2009 and 2008 is summarized as follows:
2010
2009
2008
Statutory tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35.0% 35.0% 35.0%
4.7
1.1
(5.7)
2.3
0.1
(0.2)
1.7
(1.2)
(0.2)
Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
38.2% 34.1% 35.3%
For 2008, the permanent difference indicated above was largely attributable to the Company’s 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,) and allows
a deduction of 6% in both 2008 and 2009 and 9% in 2010 and thereafter on the lesser of qualified production
activities income or taxable income. The permanent differences for 2010 and 2009 reflect the recapture of a portion
of this deduction due to the planned carryback of the 2010 net operating loss to prior years and the carryback of the
2009 net operating loss to prior years. This recapture resulted in a negative effective rate impact in 2009 due to the
Company having a loss before income taxes in that year.
F-26
The tax effect of significant temporary differences representing deferred tax assets and liabilities and changes
therein were as follows (in thousands):
December 31,
2010
Net
Change
December 31,
2009
Net
Change
December 31,
2008
Net
Change
December 31,
2007
Deferred tax assets:
Current:
Net operating loss
carryforwards . . . . . . . .
$
— $
— $
— $
— $
— $
(374) $
374
Workers’ compensation
allowance . . . . . . . . . . .
Other . . . . . . . . . . . . . . . .
Non-current:
Net operating loss
carryforwards . . . . . . . .
AMT credit . . . . . . . . . . . .
Expense associated with
employee stock options. .
Federal benefit of foreign
deferred tax liabilities . .
Federal benefit of state
deferred tax liabilities . .
Other . . . . . . . . . . . . . . . .
Total deferred tax assets . . . . . .
Deferred tax liabilities:
Current:
23,290
18,654
41,944
(1,334)
(962)
(2,296)
24,624
19,616
44,240
(1,360)
(2,735)
(4,095)
25,984
22,351
48,335
(602)
3,287
2,311
26,586
19,064
46,024
6,465
—
1,593
—
4,872
—
4,872
—
—
—
—
(118)
—
118
11,252
2,123
9,129
2,500
6,629
1,381
5,248
—
(9,160)
9,160
(256)
9,416
443
8,973
13,155
16,031
46,903
88,847
3,383
6,546
4,485
2,189
9,772
9,485
42,418
86,658
2,702
4,120
13,938
9,843
7,070
5,365
28,480
76,815
1,643
614
3,963
6,274
5,427
4,751
24,517
70,541
Other . . . . . . . . . . . . . . . .
(15,129)
(3,766)
(11,363)
1,044
(12,407)
(1,753)
(10,654)
Non-current:
Property and equipment
basis difference . . . . . . .
Other . . . . . . . . . . . . . . . .
Total deferred tax liabilities. . . .
Net deferred tax liability . . . . . .
(231,965)
(110,786)
(546,655)
(12,042)
(7,091)
(11,670)
(244,007)
(117,877)
(558,325)
(254,661)
(116,833)
(573,454)
$(484,607) $(135,828) $(348,779) $(106,990) $(241,789) $(57,669) $(184,120)
(133,542)
(709)
(134,251)
(138,017)
(302,327)
(3,870)
(306,197)
(318,604)
(413,113)
(10,961)
(424,074)
(435,437)
(70,362)
8,172
(62,190)
(63,943)
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, 2010 and 2009 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
considered 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 $35 million. Other deferred tax liabilities consist
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 $221 million of Federal net operating losses
and approximately $71.3 million of state net operating losses during the year ended December 31, 2010. Of these
amounts, approximately $257 million will be carried back to prior years, and the remaining balance can be carried
F-27
forward to future years. Net operating losses that can be carried forward, if unused, are scheduled to expire as
follows: 2014 — $9 million; 2015 — $5 million; 2019 — $12 million; 2029 — $57 million and 2030 - $18 million.
As of December 31, 2010, 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, 2010, the tax years ended December 31, 2007 through December 31, 2009 are open for examination
by U.S. taxing authorities. As of December 31, 2010, the tax years ended December 31, 2006 through December 31,
2009 are open for examination by Canadian taxing authorities.
On January 1, 2010, the Company converted its Canadian operations from a Canadian branch to a controlled
foreign corporation for Federal income tax purposes. Because the statutory tax rates in Canada are lower than those
in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being
amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the
Canadian assets.
As a result of the above conversion, the Company’s Canadian assets are no longer subject to United States
taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1,
2010, the Company has elected to permanently reinvest these unremitted earnings in Canada, and intends to do so
for the foreseeable future. As a result, no deferred United States Federal or state income taxes have been provided on
such unremitted foreign earnings, which totaled approximately $6.3 million as of December 31, 2010.
14. Employee Benefits
The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include
expenses of approximately $3.1 million in 2010, $2.8 million in 2009 and $4.5 million in 2008 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, in January 2010 the
Company exited the drilling and completion fluids services business which previously was reported as a business
segment. Operating results for that business for the years ended December 31, 2010, 2009 and 2008 are presented as
discontinued operations in the consolidated statements of operations. Also included in discontinued operations for
the year ended December 31, 2010 are the operating results for an electric wireline business that was acquired on
October 1, 2010 and sold in January 2011.
Contract Drilling — The Company markets its contract drilling services to major and independent oil and
natural gas operators. As of December 31, 2010, the Company had 356 marketable land-based drilling rigs, of which
73 of the drilling rigs were based in west Texas and southeastern New Mexico; 97 in north central and east Texas,
northern Louisiana and Mississippi; 58 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana and
North Dakota); 51 in south Texas and southern Louisiana; 32 in the Texas panhandle, Oklahoma and Arkansas; 25
in the Appalachian Basin and 20 in western Canada.
For the years ended December 31, 2010, 2009 and 2008, contract drilling revenue earned in Canada was
$65.7 million, $45.4 million and $88.5 million, respectively. Additionally, long-lived assets within the contract
drilling segment located in Canada totalled $70.7 million and $69.2 million as of December 31, 2010 and 2009,
respectively.
Pressure Pumping — The Company provides pressure pumping services to oil and natural gas operators
primarily in Texas and the Appalachian Basin. Pressure pumping services are primarily 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.
F-28
Cementing is the process of inserting material between the hole and the pipe to center and stabilize the pipe in the
hole.
Oil and Natural Gas — The Company owns and invests 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):
Revenues:
Years Ended December 31,
2009
2008
2010
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,085,722
350,608
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30,425
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 600,423
161,441
21,218
$1,808,600
217,494
42,360
Total segment revenues. . . . . . . . . . . . . . . . . . . . . . . . .
Elimination of intercompany revenues(a) . . . . . . . . . . . .
1,466,755
(3,824)
783,082
(1,136)
2,068,454
(4,574)
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,462,931
$ 781,946
$2,063,880
Income (loss) from continuing operations before income
taxes:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 140,483
62,194
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,455
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate and other . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (loss) gain on asset disposals(b) . . . . . . . . . . . . . . .
Interest income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from continuing operations before income
215,132
(37,019)
22,812
1,674
(12,772)
927
$ (11,219)
1,017
950
$ 520,636
42,019
13,711
(9,252)
(35,577)
(3,385)
381
(4,148)
426
576,366
(34,596)
4,163
1,553
(630)
502
taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 190,754
$ (51,555)
$ 547,358
Identifiable assets:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,678,250
533,597
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36,508
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
174,676
Corporate and other(c) . . . . . . . . . . . . . . . . . . . . . . . . .
$2,129,567
213,094
25,355
294,136
$2,255,421
210,805
31,760
214,831
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,423,031
$2,662,152
$2,712,817
Depreciation, depletion, amortization and impairment:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 280,458
40,724
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,950
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,361
Corporate and other . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 248,424
27,589
12,927
907
$ 239,700
19,600
15,856
834
Total depreciation, depletion, amortization and
impairment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 333,493
$ 289,847
$ 275,990
F-29
Years Ended December 31,
2009
2008
2010
Capital expenditures:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 655,550
51,064
Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23,067
Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,409
Corporate and other . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 395,376
43,144
7,341
6,785
$ 360,645
61,289
22,981
511
Total capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . $ 738,090
$ 452,646
$ 445,426
(a)
Includes contract drilling intercompany revenues related to drilling services provided to the oil and natural gas
exploration and production segment.
(b) 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.
(c) Corporate and other assets primarily include identifiable assets associated with assets held for sale as well as
cash on hand, income taxes receivable 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, 2010 and 2009, the Company’s demand deposits and temporary cash
investments consisted of the following (in thousands):
Deposits in FDIC and SIPC-insured institutions under insurance limits . . . . . . $ 1,523
51,625
Deposits in FDIC and SIPC-insured institutions over insurance limits. . . . . . .
11,533
Deposits in foreign banks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 20,543
47,376
4,383
Less outstanding checks and other reconciling items . . . . . . . . . . . . . . . . . . .
64,681
(37,069)
72,302
(22,425)
Cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 27,612
$ 49,877
2010
2009
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, 2010, 2009 or 2008. The Company recorded a provision for bad
debts for 2010, 2009 and 2008 of $(2.0) million, $3.8 million and $4.4 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. The carrying value of the balance outstanding under the term
loan facility at December 31, 2010 approximates fair value as it has a floating interest rate that adjusts at each
quarterly interest payment date. The fair value of the 4.97% Series A Senior Notes at December 31, 2010 was
approximately $290 million.
F-30
17. Quarterly Financial Information (in thousands, except per share amounts) (unaudited)
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2009
Operating revenues . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . .
Income (loss) from continuing operations, net
$268,209
25,154
$140,497
(25,855)
$159,671
(24,619)
$213,569
(22,894)
of income taxes . . . . . . . . . . . . . . . . . . . . .
15,835
(16,891)
(16,814)
(16,090)
Income (loss) from discontinued operations,
net of income taxes. . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . .
Basic income (loss) per common share:
From continuing operations . . . . . . . . . . . . .
From discontinued operations . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted income (loss) per common share:
From continuing operations . . . . . . . . . . . . .
From discontinued operations . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . .
2010
Operating revenues . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from continuing operations, net
368
16,203
(852)
(17,743)
(1,766)
(18,580)
(2,080)
(18,170)
$
$
$
$
$
$
0.10
0.00
0.11
0.10
0.00
0.11
$
$
$
$
$
$
(0.11)
(0.01)
(0.12)
(0.11)
(0.01)
(0.12)
$
$
$
$
$
$
(0.11)
(0.01)
(0.12)
(0.11)
(0.01)
(0.12)
$
$
$
$
$
$
(0.11)
(0.01)
(0.12)
(0.11)
(0.01)
(0.12)
$271,598
7,831
$306,992
45,757
$378,663
52,509
$505,678
94,828
of income taxes . . . . . . . . . . . . . . . . . . . . .
4,186
29,528
29,374
54,810
Loss from discontinued operations, net of
income taxes . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic income (loss) per common share:
From continuing operations . . . . . . . . . . . . .
From discontinued operations . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted income (loss) per common share:
From continuing operations . . . . . . . . . . . . .
From discontinued operations . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . .
—
4,186
—
29,528
—
29,374
(956)
53,854
$
$
$
$
$
$
0.03
0.00
0.03
0.03
0.00
0.03
$
$
$
$
$
$
0.19
0.00
0.19
0.19
0.00
0.19
$
$
$
$
$
$
0.19
0.00
0.19
0.19
0.00
0.19
$
$
$
$
$
$
0.36
(0.01)
0.35
0.35
(0.01)
0.35
As discussed in Note 2, the Company exited the drilling and completion fluids services business in January
2010 and sold a recently acquired wireline business in January 2011. The results of operations related to those
businesses have been reclassified and presented as discontinued operations in the quarterly financial information
above.
F-31
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Description
Year Ended December 31, 2010
Deducted from asset accounts:
Beginning
Balance
Charged to
Costs and
Expenses
Deductions(1)
Ending
Balance
(In thousands)
Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . .
$10,911
$(2,000)
$3,797
$ 5,114
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
(1) Consists of uncollectible accounts written off.
S-1
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.
SIGNATURES
PATTERSON-UTI ENERGY, INC.
By:
/s/ Douglas J. Wall
Douglas J. Wall
President and Chief Executive Officer
Date: February 14, 2011
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 14, 2011.
Signature
/s/ Mark S. Siegel
Mark S. Siegel
/s/ Douglas J. Wall
Douglas J. Wall
(Principal Executive Officer)
/s/
John E. Vollmer III
John E. Vollmer III
(Principal Financial Officer)
/s/ Gregory W. Pipkin
Gregory W. Pipkin
(Principal Accounting Officer)
/s/ Kenneth N. Berns
Kenneth N. Berns
/s/ Charles O. Buckner
Charles O. Buckner
/s/ Curtis W. Huff
Curtis W. Huff
/s/ Terry H. Hunt
Terry H. Hunt
/s/ Kenneth R. Peak
Kenneth R. Peak
/s/ Cloyce A. Talbott
Cloyce A. Talbott
Title
Chairman of the Board
President and Chief Executive Officer
Senior Vice President — Corporate Development, Chief
Financial Officer and Treasurer
Chief Accounting Officer and Assistant Secretary
Senior Vice President and Director
Director
Director
Director
Director
Director
p a T T e r S o n - U T i e n e r G y , i n C . 2 0 1 0 a n n u a l r e p o r t
c o r p o r a t e i n f o r m a t i o n
Directors
corporate officers
corporate office
transfer agent
Patterson-UTI Energy, Inc.
450 Gears Road, Suite 500
Houston, Texas 77067
Telephone: (281) 765-7100
Fax: (281) 765-7175
www.patenergy.com
Continental Stock
Transfer & Trust Company
17 Battery Place, 8th Floor
New York, NY 10004
Telephone: (212) 509-4000
www.continentalstock.com
common stock
inDepenDent auDitor
Nasdaq: PTEN
PricewaterhouseCoopers LLP
mark S. Siegel
Chairman
Douglas J. Wall
President and
Chief Executive Officer
Kenneth n. Berns
Senior Vice President
John e. Vollmer iii
Senior Vice President –
Corporate Development,
Chief Financial Officer
and Treasurer
Seth D. Wexler
General Counsel
and Secretary
Gregory W. pipkin
Chief Accounting Officer
and Assistant Secretary
mark S. Siegel
Chairman, Patterson-UTI Energy, Inc.;
President, Remy Investors and
Consultants, Incorporated
Kenneth n. Berns
Senior Vice President,
Patterson-UTI Energy, Inc.
Charles o. Buckner
Retired Partner,
Ernst & Young LLP
Curtis W. Huff
Managing Partner
Intervale Capital LLC
Terry H. Hunt
Energy Consultant
Kenneth r. peak
President and
Chief Executive Officer,
Contango Oil & Gas
Cloyce a. Talbott
Former President and
Chief Executive Officer,
Patterson-UTI Energy, Inc.
Company profile Patterson-UTI Energy, Inc. subsidiaries provide onshore
contract drilling and pressure pumping services to exploration and production
companies in North America. Patterson-UTI Drilling Company LLC has
approximately 350 marketable land-based drilling rigs that operate primarily
in the oil and natural gas producing regions of Texas, New Mexico, Oklahoma,
Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North
Dakota, Pennsylvania, West Virginia and western Canada. Universal Pressure
Pumping, Inc. and Universal Well Services, Inc. provide pressure pumping
services primarily in Texas and the Appalachian Basin.
39374bowD1R1.indd 2
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P a t t e r s o n - U t I e n e r g y , I n c . 2 0 1 0 a n n U a l r e P o r t
Patterson-UTI Energy, Inc.
450 Gears Road, Suite 500
Houston, Texas 77067
Telephone: (281) 765-7100
Fax: (281) 765-7175
www.patenergy.com
39374bowD1R1.indd 1
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