2 0 0 5 A N N U A L R E P O R T
Company Profile
Patterson-UTI Energy, Inc. provides onshore contract drilling services to exploration and
production companies in North America. The Company’s land-based drilling rigs operate
in oil and natural gas producing regions of Texas, New Mexico, Oklahoma, Louisiana,
Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and
western Canada. Patterson-UTI Energy, Inc. is also engaged in the businesses of pressure
pumping services and drilling and completion fluid services. Additionally, the Company
has an exploration and production business that is based in Texas.
Financial Highlights (in thousands, except per share amounts – unaudited)
Revenues
Operating income (loss)
Net income (loss)
Earnings (loss) per share
Basic
Diluted
Total assets
Long-term debt
Shareholders’ equity
Working capital
Operational Highlights (dollars in thousands – unaudited)
Operating days
Average revenue per day
Average margin per day (1)
Average rigs operating
Rig utilization percentage
Year ended December 31,
2001
2002
2003
2004
2005
$989,975
$527,957
$ 776,170
$1,000,769
$1,740,455
259,721
159,572
1.04
1.01
(6,892)
(4,140)
(0.03)
(0.03)
66,282
43,187
0.27
0.26
148,467
94,346
581,296
372,740
0.57
0.56
2.19
2.15
856,855
919,374
1,039,521
1,256,785
1,795,781
0
680,341
109,566
76,871
$ 10.93
$
4.59
211
70%
0
724,248
166,885
0
789,814
198,399
0
961,501
235,480
0
1,367,011
382,448
45,919
68,798
$
$
8.94
2.01
126
39%
$
$
9.30
2.39
188
56%
$
$
77,355
10.47
3.27
211
59%
$
$
100,591
14.77
7.05
276
69%
(1) Average margin per day represents average revenue per day minus average direct operating costs per day and excludes provisions for bad debts, other charges, depreciation, depletion, amortization
and impairment and selling, general and administrative expenses.
Table of Contents
Letter to Shareholders
Form 10-K
5
9
Corporate Information
Inside Back Cover
1
2
The Company also has a drilling and completion fluids business that operates in Texas,
New Mexico, Oklahoma, Louisiana and in the Gulf of Mexico. Additionally, the
Company has an exploration and production business that is based in Texas.
CONTRACT DRILLING
PRESSURE PUMPING
Market Capitalization
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Drilling Rigs Owned
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D E A R
F E L L O W S H A R E H O L D E R S :
WE ARE PLEASED TO REPORT RECORD RESULTS FROM OPERATIONS FOR 2005 AND TO
SHARE OUR OUTLOOK FOR 2006, WHICH WE BELIEVE WILL BE ANOTHER RECORD YEAR
FOR PATTERSON-UTI ENERGY, INC.
In 2005 we achieved record-setting performances
investing in upgrading and refurbishing
from all of our operating units, including pressure
existing equipment, and maintaining a
pumping, drilling and completion fluids, oil
strong infrastructure.
and natural gas exploration and production,
Increased Drilling Fleet: Five years ago
along with our largest operating unit, contract
Patterson and UTI owned 302 land-based
Revenues
land drilling, which generated 85 percent of
drilling rigs; today we own 403 drilling rigs
our revenue.
Highlights From 2005
that operate primarily in the oil and natural
gas producing regions of Texas, New Mexico,
Oklahoma, Louisiana, Mississippi, Colorado,
■ Record Earnings: Net income increased
Utah, Wyoming, Montana, North Dakota,
by nearly 300 percent to $373 million, or
South Dakota and western Canada. We have
$2.15 per share.
been able to significantly increase our drilling
■ Record Revenues: Revenues increased by
rig fleet without mortgaging our future. These
74 percent to $1.7 billion.
acquisitions have been financed primarily by
■ Strong Balance Sheet: Approximately
cash generated from operations, rather than
$136 million in cash and cash equivalents,
through the issuance of common stock or the
$382 million in working capital and no
incurrence of debt.
long-term debt as of December 31, 2005.
Upgrading and Refurbishing Rigs: While we
■ Record Drilling Margin: Average drilling
have increased the number of rigs that we own,
margin increased by 116 percent to
we have also invested in upgrading our existing
$7,050 per operating day.
rigs. In addition, we began a program of
refurbishing stacked rigs in 2004 which
Successful Strategy
significantly increased our active rig fleet. We
While 2005 was a positive year for our industry,
continue to have a substantial portion of the
it was a record-breaking year for Patterson-UTI
incremental capacity in the land drilling industry.
Energy, Inc. Our earnings increased nearly 300
Maintaining Key Field Personnel: We recognize
percent on a 74 percent increase in revenues.
the importance of maintaining key field personnel
We believe that these results are a direct result
and the need for attracting experienced
of our consistent commitment to position
managerial staff. We believe we have developed
Patterson-UTI Energy for long-term growth
an infrastructure that is able to react quickly
and profitability by increasing our drilling fleet,
and efficiently to the needs of our customers.
1,800
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Rig Utilization
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6
Favorable Commodity Environment
have found that this measured approach allows
Both oil and natural gas markets continued to
us time to prepare rigs properly for activation
be favorable in 2005. Oil averaged $56.49 per
and to train crews, which permits us to maintain
bbl (WTI), a 36 percent increase over the prior
efficiency for our customers.
year, and natural gas averaged $8.98 per mcf, a
51 percent increase over the prior year. With
Stock Buyback Program
these higher commodity prices, demand for
On March 27, 2005 the Board approved an
drilling services continued to increase significantly
increase in the Company’s stock buyback
during the year.
Looking Ahead
program, authorizing the purchase of up to
$200 million of the Company’s common stock.
The increase in the stock buyback program
Looking ahead, we see continued strong demand
demonstrates continued confidence in the
for our rigs and an ongoing scarcity of rigs in
Company’s strong cash flow and our continuing
the overall market. To paraphrase a line from
commitment to deploy excess capital in a manner
Mark Twain and a recent analyst comment, we
beneficial to shareholders.
believe that the reports of the demise of the
land drilling segment are greatly exaggerated.
An Unfortunate Occurrence
The demand for rigs, and indeed our services in
Unfortunately, our record performance in 2005
pressure pumping and fluids, remains strong,
was marred by the discovery in November 2005
and we continue to see a land drilling market
that Jonathan D. Nelson, the former Chief
characterized by a scarcity of rigs. We have seen
Financial Officer, had embezzled approximately
no indication that customers – whether large or
$78 million from the Company over a more
small – have retreated or plan to retreat from
than five-year period. Upon the Company’s
their drilling programs.
discovery of the embezzlement: (a) the
Although natural gas prices have declined
Company obtained a confession from Mr.
since the highs following Hurricane Katrina and
Nelson, (b) the Company notified the SEC and
the start of winter, we believe that current prices
law enforcement authorities of the loss, and (c)
and the expectations with respect to future prices
the Company’s Audit Committee conducted a
are such that our customers will continue with
thorough investigation, which revealed the
their expanded drilling efforts. We believe that
means by which the embezzlement was
the price expectations for natural gas, currently
committed and the fact that no other Company
reflected in the futures market, are well above the
employees knowingly participated. As of today,
“price deck” used by our customers to determine
(i) the Company is current with all of its
whether to drill wells. Based on what we are
required public disclosure, (ii) Mr. Nelson has
seeing from our customers, our plan for 2006 is
pled guilty to wire fraud and money laundering
to activate approximately 30 rigs in 2006. We
and is awaiting sentencing, and (iii) the SEC
Cash Flow From
Operating Activities
500
450
400
400
350
300
250
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150
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7
has instituted a receivership proceeding to
Conclusions
recover the stolen money on behalf of the
The positive results for 2005 would not have
Company and other creditors. We deeply regret
been possible without the skill and dedication
that this embezzlement occurred, but we believe
of employees throughout our Company – from
that the Company’s management and Board of
those who work in the field to those who serve
Directors responded in a timely and intelligent
in administrative and support roles. We appreciate
manner to address the issues facing the Company
their contribution and commitment to serving
as soon as they were revealed. We firmly believe
the needs of our customers. As always, we are
that we have emerged a far stronger Company
appreciative of the support that we have received
and we continue to strive to use this unfortunate
over the past year and are mindful of the fiduciary
occurrence as an opportunity for improvement.
responsibilities and obligations that we bear. We
pledge to continue to do all that we can to be
worthy of the trust and confidence that has
been placed in us.
Respectfully submitted,
Mark S. Siegel
Chairman
Cloyce A. Talbott
President and
Chief Executive Officer
8
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 Ñscal year ended December 31, 2005
or
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
Patterson-UTI Energy, Inc.
(Exact name of registrant as speciÑed in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
4510 Lamesa Highway, Snyder, Texas
(Address of principal executive oÇces)
75-2504748
(I.R.S. Employer
IdentiÑcation No.)
79549
(Zip Code)
Registrant's telephone number, including area code:
(325) 574-6300
Securities Registered Pursuant to 12(b) of the Act:
None
Securities Registered Pursuant to 12(g) of the Act:
(Title of class)
Common Stock, $.01 Par Value
Indicate by check mark if the registrant is a well-known seasoned issuer, as deÑned in Rule 405 of the Securities
Act. Yes ¥ or No n
Indicate by check mark if the registrant is not required to Ñle reports pursuant to Section 13 or Section 15(d) of
the Act. Yes n or No ¥
Indicate by check mark whether the registrant (1) has Ñled all reports required to be Ñled 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 Ñle such reports), and (2) has been subject to such Ñling requirements for the past
90 days. Yes ¥
No n
Indicate by check mark if disclosure of delinquent Ñlers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of the registrant's knowledge, in deÑnitive 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 Ñler, an accelerated Ñler, or a non-
accelerated Ñler. See deÑnition of ""accelerated Ñler and large accelerated Ñler'' in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated Ñler ¥
Non-accelerated Ñler n
Indicate by check mark whether the registrant is a shell company (as deÑned in Rule 12b-2 of the
Accelerated Ñler n
Act). Yes n
No ¥
The aggregate market value of the voting and non-voting common equity held by non-aÇliates of the registrant as
of June 30, 2005, the last business day of the registrant's most recently completed second Ñscal quarter, was
$4,657,765,918, calculated by reference to the closing price of $27.83 for the common stock on the Nasdaq National
Market on that date.
As of March 29, 2006, the registrant had outstanding 172,653,028 shares of common stock, $.01 par value, its
only class of voting common stock.
Documents incorporated by reference:
DeÑnitive Proxy Statement for the 2006 Annual Meeting of Stockholders (Part III).
FORWARD LOOKING STATEMENTS
This Annual Report on Form 10-K (including documents incorporated by reference herein) contains
statements with respect to our expectations and beliefs as to future events. These types of statements are
""forward-looking'' and subject to uncertainties. Readers are cautioned that such forward-looking statements
should be read in conjunction with our disclosures under the heading ""Risk Factors,'' beginning on page 11.
Item 1. Business
Available Information
PART I
This Annual Report on Form 10-K, along with our Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K and amendments to those reports Ñled or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, are available free of charge through our Internet website
(www.patenergy.com) as soon as reasonably practicable after we electronically Ñle such material with, or
furnish it to, the United States Securities and Exchange Commission (""SEC'').
Overview
Based on publicly available information, we believe we are the second largest owner of land-based drilling
rigs in North America. 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,
‚ Louisiana,
‚ Mississippi,
‚ Colorado,
‚ Utah,
‚ Wyoming,
‚ Montana,
‚ North Dakota,
‚ South Dakota, and
‚ Western Canada (Alberta, British Columbia and Saskatchewan).
As of December 31, 2005, we had a drilling Öeet of 403 drilling rigs. A drilling rig includes the structure,
power source and machinery necessary to cause a drill bit to penetrate earth to a depth desired by the
customer.
We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian
Basin. These services consist primarily of well stimulation and cementing for completion of new wells and
remedial work on existing wells. We provide drilling Öuids, completion Öuids and related services to oil and
natural gas operators in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and
the Gulf of Mexico. Drilling and completion Öuids are used by oil and natural gas operators during the drilling
process to control pressure when drilling oil and natural gas wells. We are also engaged in the development,
exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused
primarily in producing regions of West and South Texas, Southeastern New Mexico, Utah and Mississippi.
1
Embezzlement and Restatements
On November 3, 2005, we announced the resignation of our Chief Financial OÇcer (""CFO''), Jonathan
D. Nelson (""Nelson''). On November 10, 2005, we announced that, based on information received by
Company senior management on November 9, 2005, the Audit Committee of our Board of Directors began an
investigation into an apparent embezzlement from us by Nelson.
On December 22, 2005, upon recommendation of Company management and the Audit Committee of
our Board of Directors, we announced that based on the results to date of the internal investigation into the
facts and circumstances surrounding the embezzlement by Nelson, we would restate previously issued
Ñnancial statements and amend our previously issued Annual Report on Form 10-K for the year ended
December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and
September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the
beneÑt of Nelson that had been recognized in our accounting records and previously issued Ñnancial
statements as payments for assets and services that we did not receive. Previously issued Ñnancial statements
have also been restated for the eÅects of the correction of other errors that are immaterial both individually
and in the aggregate. These other adjustments relate primarily to previously reported property and equipment
balances that resulted from our review of our property and equipment records and the underlying physical
assets in connection with investigation of the embezzlement. We have restated such Ñnancial statements, and
on March 17, 2006, we Ñled our amended Annual Report on Form 10-K/A and on March 27, 2006, we Ñled
our amended Quarterly Reports on Form 10-Q/A with the SEC.
Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating
approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was
originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one
of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson
initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent
invoices containing forged senior management approvals. This false documentation was created by Nelson to
conceal the true nature of these transactions from the Company and its independent registered public
accountants.
Nelson also instructed certain former employees, who worked under his supervision, to alter management
reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment
approval forms with forged signatures.
The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects,
beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):
From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ
Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$58,961
12,193
71,154
6,350
$77,504
(1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of
professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds
and related expenses in 2005 were $20,043,000.
We promptly advised the SEC when we became aware of the embezzlement. The SEC promptly
obtained a freeze order on Nelson's assets (including assets held by entities controlled by him) and a Receiver
was appointed to collect those assets. The United States attorney for the Northern District of Texas obtained
an indictment against Nelson and investigation of this matter continues.
The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to
distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled,
other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the
2
Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be
recognized when they are considered collectable.
The eÅects of the embezzlement on our Ñnancial position follow (in thousands):
Decrease in amounts previously reported
December 31,
2004
2003
Assets(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Liabilities(2) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Retained earnings and stockholders' equityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$(56,133)
(20,848)
$(35,285)
$(38,540)
(15,044)
$(23,496)
(1) The amount includes a decrease in Federal and state income taxes receivable of $1.0 million in 2003.
(2) Consists of an increase in Federal and state income taxes payable of $1.3 million in 2004 and decreases in
deferred tax liabilities of $22.2 million and $15.0 million in 2004 and 2003, respectively.
In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County,
Texas, against our directors, alleging that the directors breached their Ñduciary duties to us as a result of
alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation
committee to review and inquire about these allegations and recommend our response, if any. The lawsuits
seek recovery on behalf of and for us and do not seek recovery from us.
The Ñnancial statements and related Ñnancial and statistical data contained in this Report have been
restated to provide for, net of related tax eÅects, (1) the eÅects of losses incurred as a result of the
embezzlement and (2) the eÅects of the correction of other errors that are immaterial both individually and in
the aggregate.
Industry Segments
Our revenues, operating proÑts and identiÑable assets are primarily attributable to four industry segments:
‚ contract drilling,
‚ pressure pumping services,
‚ drilling and completion Öuids services, and
‚ oil and natural gas development, exploration, acquisition and production.
With respect to these four segments:
‚ the contract drilling segment had operating proÑts in 2005, 2004 and 2003,
‚ the pressure pumping segment had operating proÑts in 2005, 2004 and 2003,
‚ the drilling and completion Öuids segment had operating proÑts in 2005 and 2004 and an operating loss
in 2003, and
‚ the oil and natural gas segment had operating proÑts in 2005, 2004 and 2003.
See ""Management's Discussion and Analysis of Financial Condition and Results of Operations'' and
Note 17 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of
this Report for Ñnancial information pertaining to these industry segments.
Contract Drilling Operations
General Ì We market our contract drilling services to major and independent oil and natural gas
operators. As of December 31, 2005, we owned 403 drilling rigs which were based in the following regions:
‚ 156 in the Permian Basin region (West Texas and Southeastern New Mexico),
‚ 53 in South Texas,
3
‚ 42 in the Ark-La-Tex region and Mississippi,
‚ 88 in the Mid-Continent region (Oklahoma and North Central Texas),
‚ 46 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana, North Dakota and South
Dakota), and
‚ 18 in Western Canada (Alberta, British Columbia and Saskatchewan).
Our drilling rigs have rated maximum depth capabilities ranging from 4,000 feet to 30,000 feet. Of our drilling
rigs, 42 are SCR electric rigs and 361 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.
Drilling rigs are typically equipped with:
‚ engines,
‚ drawworks or hoists,
‚ derricks or masts,
‚ pumps to circulate the drilling Öuid,
‚ blowout preventers,
‚ drill string (pipe), and
‚ other related equipment.
Over time, components on a drilling rig are replaced or rebuilt. We spend signiÑcant funds each year on
an ongoing program to modify and upgrade our drilling rigs to ensure that our drilling equipment is well
maintained and competitive. During Ñscal years 2005, 2004 and 2003, we spent approximately $329 million,
$141 million and $77 million, respectively, on capital improvements to modify and upgrade our drilling rigs.
Depth of the well and drill site conditions are the principal factors in determining the size of drilling rig
used for a particular job. We use our rigs for developmental and exploratory drilling and they are capable of
vertical or horizontal drilling.
Our contract drilling operations depend on the availability of:
‚ drill pipe,
‚ bits,
‚ replacement parts and other related rig equipment,
‚ fuel, and
‚ qualiÑed personnel,
some of which have been in short supply from time to time.
Drilling Contracts Ì Most of our drilling contracts are with established customers on a competitive bid or
negotiated basis. Typically, the contracts are short-term to drill a single well or a series of wells. Customer
demand for drilling contracts with a term of one or more years increased during 2005 due to the scarcity of
available drilling rigs in the market place. In response to this demand, we entered into several long-term
contracts in 2005, typically with a term of one year. We may continue to enter into long-term contracts when
considered beneÑcial to the Company.
The 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. The contracts are
generally subject to termination by the customer on short notice. We generally 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. The customers generally indemnify us against claims that
4
might arise from other surface and subsurface pollution, except claims that might arise from our gross
negligence.
The 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 contract 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.
Daywork Contracts
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. In the past we generally received a lower rate when the drilling rig was moving, or when drilling
operations were interrupted or restricted by conditions beyond our control. Current market conditions have
enabled us to receive rates at or near current daywork dayrates in many of these situations. In addition,
daywork contracts typically provide separately for mobilization of the drilling rig.
Footage Contracts
Under footage contracts, we contract to drill a well to a certain depth under speciÑed conditions for a
Ñxed price per foot. The customer provides drilling Öuids, casing, cementing and well design expertise. These
contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to
the agreed depth. If we drill the well in less time than estimated, we have the opportunity to improve our
proÑts over those that would be attainable under a daywork contract. ProÑts 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 assumes certain risks associated with loss of the well from Ñre, blowouts and other risks.
Due to current market conditions and improved rates received under daywork contracts, we are entering into
fewer footage contracts than we did in the past.
Turnkey Contracts
Under turnkey contracts, we contract to drill a well to a certain depth under speciÑed conditions for a
Ñxed 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 Öuids, casing, cementing, and the technical well design and
engineering services during the drilling process. We also assume certain risks associated with drilling the well
such as Ñres, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the
agreed scope of the work has been completed which requires us to make larger up-front working capital
commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have
the opportunity to improve our proÑts if the drilling process goes as expected and there are no complications or
time delays. However, given the increased exposure we have under a turnkey contract, proÑts can be
signiÑcantly reduced and losses incurred if complications or delays occur during the drilling process. Turnkey
contracts generally involve the highest degree of risk among the three diÅerent types of drilling contracts:
daywork, footage and turnkey. Due to current market conditions and improved rates received under daywork
contracts, we are entering into fewer turnkey contracts than we did in the past.
5
Revenues by Contract Type Ì Information regarding our contract drilling activity for the last three years
follows:
Type of Revenues
Years Ended December 31,
2003
2004
2005
DayworkÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Footage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Turnkey ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
98%
1
1
88%
6
6
83%
7
10
Contract Drilling Activity Ì Information regarding our contract drilling activity for the last three years
follows:
Years Ended December 31,
2003
2004
2005
Average rigs ownedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operating(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rig utilization rate ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Number of rigs operated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Number of wells drilled ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
397
276
359
211
336
188
69%
59%
56%
307
4,594
259
3,534
226
3,017
(1) A rig is operating when it is drilling, being moved, assembled, dismantled or otherwise earning revenue
under contract.
Drilling Rigs and Related Equipment Ì Certain drilling rig information as of December 31, 2005 follows:
Depth Rating (Ft.)
Mechanical
Electric
Total
4,000 to 9,999 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
10,000 to 11,999 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
12,000 to 14,999 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
15,000 to 30,000 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
TotalsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
79
76
139
67
361
Ì
2
8
32
42
79
78
147
99
403
At December 31, 2005, we owned 390 trucks and 467 trailers used to rig down, transport and rig up our
drilling rigs. This reduces our dependency upon third parties for these services and enhances the eÇciency 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, New Mexico, Oklahoma, Utah and Western Canada.
Pressure Pumping Operations
General Ì We provide pressure pumping services to oil and natural gas operators primarily in the
Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for the
completion of new wells and remedial work on existing wells. Most wells drilled in the Appalachian Basin
require some form of fracturing or other stimulation to enhance the Öow of oil and natural gas by pumping
Öuids under pressure into the well bore. Generally, Appalachian Basin wells require cementing services before
production commences. The cementing process inserts material between the wall of the well bore and the
casing to center and stabilize the casing.
Equipment Ì Our pressure pumping equipment at December 31, 2005 follows:
‚ 30 cement pumper trucks,
‚ 33 fracturing pumper trucks,
‚ 30 nitrogen pumper trucks,
6
‚ 17 blender trucks,
‚ 10 bulk acid trucks,
‚ 37 bulk cement trucks,
‚ 10 bulk nitrogen trucks,
‚ 42 bulk sand trucks,
‚ 15 connection trucks, and
‚ 2 acid pumper trucks.
Drilling and Completion Fluids Operations
General Ì We provide drilling Öuids, completion Öuids and related services to oil and natural gas
operators oÅshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the
Gulf Coast region of Louisiana. We serve our oÅshore customers through six stockpoint facilities located along
the Gulf of Mexico in Texas and Louisiana and our land-based customers through eleven stockpoint facilities
in Texas, Louisiana, Oklahoma and New Mexico.
Drilling Fluids Ì Drilling Öuid products and systems are used to cool and lubricate the bit during drilling
operations, contain formation pressures (thereby minimizing blowout risk), suspend and remove rock cuttings
from the hole and maintain the stability of the wellbore. Technical services are provided to ensure that the
products and systems are applied eÅectively to optimize drilling operations.
Completion Fluids Ì After a well is drilled, the well casing is set and cemented into place. At that point,
the drilling Öuid services are complete and the drilling Öuids are circulated out of the well and replaced with
completion Öuids. Completion Öuids, also known as clear brine Öuids, are solids-free, clear salt solutions that
have high speciÑc gravities. Combined with a range of specialty chemicals, these Öuids are used to control
bottom-hole pressures and to meet speciÑc corrosion, inhibition, viscosity and Öuid loss requirements.
Raw Materials Ì Our drilling and completion Öuids operations depend on the availability of the
following raw materials:
Drilling
barite and bentonite
Completion
calcium chloride, calcium bromide and zinc bromide
We obtain these raw materials through purchases made on the spot market and supply contracts with
producers of these raw materials.
Barite Grinding Facility Ì We own and operate a barite grinding facility with two barite grinding mills in
Houma, Louisiana. This facility allows us to grind raw barite into the powder additive used in drilling Öuids.
Other Equipment Ì We own 24 trucks and 79 trailers and lease another 24 trucks which are used to
transport drilling and completion Öuids and related equipment.
Oil and Natural Gas Operations
General Ì We are engaged in the development, exploration, acquisition and production of oil and natural
gas. Our oil and natural gas business operates primarily in producing regions of West and South Texas,
Southeastern New Mexico, Utah and Mississippi. We signiÑcantly expanded our oil and natural gas operations
in 2004 through our acquisition of TMBR/Sharp Drilling, Inc. (""TMBR''). The oil and natural gas assets
acquired in the acquisition of TMBR included both proved reserves and undeveloped properties.
7
Customers
The customers of each of our four business segments are oil and natural gas operators or purchasers of
these commodities. Our customer base includes both major and independent oil and natural gas operators.
During 2005, no single customer accounted for 10% or more of our consolidated operating revenues.
Competition
Contract Drilling and Pressure Pumping Businesses Ì Our land drilling and pressure pumping businesses
are highly competitive. Often times, available land drilling rigs and pressure pumping equipment exceed the
demand for such equipment. The equipment can also be moved from one market to another in response to
market conditions.
Drilling and Completion Fluids Business Ì The drilling and completion Öuids industry is highly
competitive and price is generally the most important factor. Other competitive factors include the availability
of chemicals and experienced personnel, the reputation of the Öuids services provider in the drilling industry
and relationships with customers. Some of our competitors have substantially more resources and longer
operating histories than we have.
Oil and Natural Gas Business Ì There is substantial competition for the acquisition of oil and natural gas
leases suitable for development and exploration and for experienced personnel. Our competitors in this
business include:
‚ major integrated oil and natural gas operators,
‚ independent oil and natural gas operators, and
‚ drilling and production purchase programs.
Our ability to increase our oil and natural gas reserves in the future is directly dependent upon our ability
to select, acquire and develop suitable prospects. Many of our competitors have facilities and Ñnancial and
human resources greater than ours.
Government and Environmental Regulation
All of our operations and facilities are subject to numerous Federal, state, foreign, and local laws, rules
and regulations related to various aspects of our business, including:
‚ drilling of oil and natural gas wells,
‚ containment and disposal of hazardous materials, oilÑeld waste, other waste materials and acids,
‚ use of underground storage tanks, and
‚ use of underground injection wells.
To date, applicable environmental laws and regulations have not required the expenditure of signiÑcant
resources. We do not anticipate any material capital expenditures for environmental control facilities or
extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future.
However, compliance costs under existing laws or under any new requirements could become material and we
could incur liability in any instance of noncompliance.
Our business is generally aÅected by political developments and by Federal, state, foreign, and local laws
and regulations, which relate to the oil and natural gas industry. The adoption of laws and regulations aÅecting
the oil and natural gas industry for economic, environmental and other policy reasons could increase costs
relating to drilling and production. They could have an adverse eÅect on our operations. Several state and
Federal environmental laws and regulations currently apply to our operations and may become more stringent
in the future.
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
8
operated by us or our predecessors. 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.
The Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as
amended, commonly known as CERCLA, and comparable state statutes impose strict liability on:
‚ owners and operators of sites, and
‚ persons who disposed of or arranged for the disposal of ""hazardous substances'' found at sites.
The Federal Resource Conservation and Recovery Act (""RCRA''), as amended, and comparable state
statutes govern the disposal of ""hazardous wastes.'' Although CERCLA currently excludes petroleum from
the deÑnition 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 modiÑed in the future. If such changes are made to CERCLA and/or RCRA, we could be
required to remove and remediate previously disposed of materials (including materials disposed of or released
by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and
to perform removal or remedial actions to prevent future contamination.
The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and
implementing regulations govern:
‚ the prevention of discharges, including oil and produced water spills, and
‚ liability for drainage into waters.
The Oil Pollution Act is more comprehensive and stringent than previous oil pollution liability and
prevention laws. It imposes strict liability for a comprehensive and expansive list of damages from an oil spill
into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private
damages. Penalties may also be imposed for violation of Federal safety, construction and operating regulations,
and for failure to report a spill or to cooperate fully in a clean-up.
The Oil Pollution Act also expands the authority and capability of the Federal government to direct and
manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases
where it can reasonably be expected that substantial harm will be done to the environment by discharges on or
into navigable waters. We have spill prevention control and countermeasure plans in place for our oil and
natural gas properties in each of the areas in which we operate and for each of the stockpoints operated by our
drilling and completion Öuids business. Failure to comply with ongoing requirements or inadequate coopera-
tion during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the
liability for owners and operators is the same under the Federal Water Pollution Act, the damages recoverable
under the Oil Pollution Act are potentially much greater and can include natural resource damages.
Our operations are also subject to Federal, state and local regulations for the control of air emissions. The
Federal Clean Air Act, as amended, and various state and local laws impose certain air quality requirements
on us. Amendments to the Clean Air Act revised the deÑnition of ""major source'' such that emissions from
both wellhead and associated equipment involved in oil and natural gas production may be added to determine
if a source is a ""major source.'' As a consequence, more facilities may become major sources and thus would
be required to obtain operating permits. This permitting process may require capital expenditures in order to
comply with permit limits.
Risks and Insurance
Our operations are subject to the many hazards inherent in the drilling business, including:
‚ accidents at the work location,
‚ blow-outs,
‚ cratering,
9
‚ Ñres, and
‚ explosions.
These hazards could cause:
‚ personal injury or death,
‚ suspension of drilling operations, or
‚ serious damage or destruction of the equipment involved and, in addition to environmental damage,
could cause substantial damage to producing formations and surrounding areas.
Damage to the environment, including property contamination in the form of either soil or ground water
contamination, could also result from our operations, particularly through:
‚ oil or produced water spillage,
‚ natural gas leaks, and
‚ Ñres.
In addition, we could become subject to liability for reservoir damages. The occurrence of a signiÑcant
event, including pollution or environmental damages, could materially aÅect our operations and Ñnancial
condition.
As a protection against operating hazards, we maintain insurance coverage we believe to be adequate,
including:
‚ all-risk physical damages,
‚ employer's liability,
‚ commercial general liability, and
‚ workers compensation insurance.
We believe that we are adequately insured for public liability and property damage to others with respect
to our operations. However, such insurance may not be suÇcient to protect us against liability for all
consequences of:
‚ personal injury,
‚ well disasters,
‚ extensive Ñre damage,
‚ damage to the environment, or
‚ other hazards.
We also carry insurance coverage for major physical damage to our drilling rigs. However, we do not carry
insurance against loss of earnings resulting from such damage. In view of the diÇculties that may be
encountered in renewing such insurance at reasonable rates, no assurance can be given that:
‚ we will be able to maintain the type and amount of coverage that we believe to be adequate at
reasonable rates, or
‚ any particular types of coverage will be available.
In addition to insurance coverage, we also attempt to obtain indemniÑcation from our customers for
certain risks. These indemnity agreements typically require our customers to hold us harmless in the event of
loss of production or reservoir damage. These contractual indemniÑcations may not be supported by adequate
insurance maintained by the customer.
10
Employees
We employed approximately 8,600 full-time persons (450 oÇce personnel and 8,150 Ñeld personnel) at
December 31, 2005. The number of Ñeld employees Öuctuates 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 signiÑcantly aÅect our overall operations. However, our pressure pumping division in
Appalachia and our drilling operations in Canada are subject to slow periods of activity during the Spring
thaw. In addition, our drilling operations in Canada are subject to slow periods of activity during the Fall.
Raw Materials and Subcontractors
We use many suppliers of raw materials and services. These materials and services have historically been
available, although there is no assurance that such materials and services will continue to be available on
favorable terms or at all. We also utilize numerous independent subcontractors from various trades.
Incorporation by Reference
The various factors disclosed under the caption ""Risk Factors,'' beginning on page 11 of this Report, are
incorporated by this reference into Items 1 and 2 of this Report. Readers of this Report should review those
factors in conjunction with their review of this Report.
Item 1A. Risk Factors.
From time to time, we make written or oral forward-looking statements, including statements contained
in this Annual Report on Form 10-K, our other Ñlings with the SEC, press releases and reports to
stockholders. These forward-looking statements are made pursuant to the ""Safe Harbor'' provisions of the
Private Securities Litigation Reform Act of 1995. These statements include, without limitation, statements
relating to liquidity, Ñnancing of operations, sources and suÇciency of funds and impact of inÖation. The
words ""believes,'' ""budgeted,'' ""expects,'' ""project,'' ""will,'' ""could,'' ""may,'' ""plans,'' ""intends,'' ""strategy,'' or
""anticipates,'' and similar expressions are used to identify our forward-looking statements. We do not
undertake to update, revise, or correct any of our forward-looking information.
We include the following cautionary statement in accordance with the ""Safe Harbor'' provisions of the
Private Securities Litigation Reform Act of 1995 for any forward-looking statement made by us, or on our
behalf. The factors identiÑed in this cautionary statement are important factors (but not necessarily all of the
important factors) that could cause actual results to diÅer materially from those expressed in any forward-
looking statement made by us, or on our behalf. Where any such forward-looking statement includes a
statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we
believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases
almost always vary from actual results. The diÅerences between assumed facts or bases and actual results can
be material, depending upon the circumstances.
Where, in any forward-looking statement, we express an expectation or belief as to the future results,
such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there
can be no assurance that the statement of expectation or belief will result, or be achieved or accomplished.
11
Taking this into account, the following are identiÑed as important risk factors currently applicable to, or which
could readily be applicable to, us:
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 AÅected Our Operations.
Our revenue, proÑtability and rate of growth are substantially dependent upon prevailing prices for oil and
natural gas. For many years, oil and natural gas prices and, therefore, the level of drilling, exploration,
development and production, have been extremely volatile. Prices are aÅected by:
‚ market supply and demand,
‚ international military, political and economic conditions, and
‚ the ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set
and maintain production and price targets.
All of these factors are beyond our control. Natural gas prices fell from an average of $6.23 per Mcf in the
Ñrst quarter of 2001 to an average of $2.51 per Mcf for the same period in 2002. During this same period, the
average number of our rigs operating dropped by approximately 50%. The average market price of natural gas
improved from $3.36 in 2002 to $8.98 in 2005 resulting in an increase in demand for our drilling services. Our
average number of rigs operating increased from 126 in 2002 to 276 in 2005. We expect oil and natural gas
prices to continue to be volatile and to aÅect our Ñnancial condition and operations and ability to access
sources of capital. A signiÑcant decrease in expected market prices for natural gas could result in a material
decrease in demand for drilling rigs and reduction in our operating results.
A General Excess of Operable Land Drilling Rigs Adversely AÅects Our ProÑt Margins Particularly in
Times of Weaker Demand.
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 diÇculty sustaining proÑt margins during the downturn
periods.
In addition to adverse eÅects that future declines in demand could have on us, ongoing factors which
could adversely aÅect utilization rates and pricing, even in an environment of high oil and natural gas prices
and increased drilling activity, include:
‚ movement of drilling rigs from region to region,
‚ reactivation of land-based drilling rigs, or
‚ construction of new drilling rigs.
We cannot predict either the future level of demand for our contract drilling services or future conditions
in the oil and natural gas contract drilling business.
Shortages of Drill Pipe, Replacement Parts and Other Related Rig Equipment Adversely AÅects Our
Operating Results.
During periods of increased demand for drilling services, the industry has experienced shortages of drill
pipe, replacement parts and other related rig equipment. These shortages can cause the price of these items to
increase signiÑcantly and require that orders for the items be placed well in advance of expected use. These
price increases and delays in delivery may require us to increase capital and repairs expenditures in our
contract drilling segment. Severe shortages could impair our ability to operate our drilling rigs.
12
The Various Business Segments in Which We Operate Are Highly Competitive with Excess Capacity
which may Adversely AÅect Our Operating Results.
Our land drilling and pressure pumping businesses are highly competitive. While not the conditions at
present, often 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 for the
foreseeable future 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.
The drilling and completion Öuids services industry is highly competitive. Price is generally the most
important factor. Other competitive factors include the availability of chemicals and experienced personnel,
the reputation of the Öuids services provider in the drilling industry and relationships with customers. Some of
our competitors have substantially more resources and longer operating histories than we have.
Labor Shortages Adversely AÅect Our Operating Results.
During periods of increasing demand for contract drilling services, the industry experiences shortages of
qualiÑed drilling rig personnel. During these periods, our ability to attract and retain suÇcient qualiÑed
personnel to market and operate our drilling rigs is adversely aÅected which negatively impacts both our
operations and proÑtability. Operationally, it is more diÇcult to hire qualiÑed personnel which adversely
aÅects our ability to mobilize inactive rigs in response to the increased demand for our contract drilling
services. Additionally, wage rates for drilling personnel are likely to increase, resulting in greater operating
costs.
Continued Growth Through Rig Acquisition is Not Assured.
We have increased our drilling rig Öeet over the past several years through mergers and acquisitions. The
land drilling industry has experienced signiÑcant consolidation over the past several years, and there can be no
assurance that acquisition opportunities will continue to be available. Additionally, we are likely to continue to
face intense competition from other companies for available acquisition opportunities.
There can be no assurance that we will:
‚ have suÇcient capital resources to complete additional acquisitions,
‚ successfully integrate acquired operations and assets,
‚ eÅectively manage the growth and increased size,
‚ successfully deploy idle or stacked rigs,
‚ maintain the crews and market share to operate drilling rigs acquired, or
‚ successfully improve our Ñnancial condition, results of operations, business or prospects in any material
manner as a result of any completed acquisition.
We may incur substantial indebtedness to Ñnance future acquisitions and also may issue equity securities
or convertible securities in connection with any such acquisitions. Debt service requirements could represent a
signiÑcant burden on our results of operations and Ñnancial 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.
13
The Nature of our Business Operations Presents Inherent Risks of Loss that, if not Insured or
IndemniÑed Against, Could Adversely AÅect Our Operating Results.
Our operations are subject to many hazards inherent in the contract drilling, pressure pumping, and
drilling and completion Öuids 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 indemniÑcation agreements with many of our customers. However,
there is no assurance that such insurance or indemniÑcation agreements would adequately protect us against
liability or losses from all consequences of the 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 signiÑcantly in the future, so as to make such insurance prohibitive.
We have elected in some cases to accept a greater amount of risk through increased deductibles on
certain insurance policies. For example, we maintain a $1.0 million per occurrence deductible on our workers'
compensation insurance and our general liability insurance coverages. These levels of self-insurance expose us
to increased operating costs and risks.
Violations of Environmental Laws and Regulations Could Materially Adversely AÅect Our Operating
Results.
The drilling of oil and natural gas wells is subject to various Federal, state, foreign, and local laws, rules
and regulations. The cost of compliance with these laws and regulations could be substantial. Failure to
comply with these requirements could expose us to substantial civil and criminal penalties. In addition,
Federal law imposes a variety of regulations on ""responsible parties'' related to the prevention of oil spills and
liability for damages from such spills. As an owner and operator of land-based drilling rigs, we may be deemed
to be a responsible party under Federal law. Our operations and facilities are subject to numerous state and
Federal environmental laws, rules and regulations, including, without limitation, laws concerning the
containment and disposal of hazardous substances, oil Ñeld waste and other waste materials, the use of
underground storage tanks and the use of underground injection wells.
Some of Our Contract Drilling Services are Done Under Turnkey and Footage Contracts, Which are
Financially Risky.
A portion of our contract drilling is performed under turnkey and footage contracts, which involve
signiÑcant risks. Under turnkey drilling contracts, we contract to drill a well to a certain depth under speciÑed
conditions at a Ñxed price. Under footage contracts, we contract to drill a well to a certain depth under
speciÑed conditions at a Ñxed price per foot. The risk to us under these types of drilling contracts are greater
than on a well drilled on a daywork basis. Unlike daywork contracts, we must bear the cost of services until the
target depth is reached. In addition, we must assume most of the risk associated with the drilling operations,
generally assumed by the operator of the well on a daywork contract, including blowouts, loss of hole from Ñre,
machinery breakdowns and abnormal drilling conditions. Accordingly, if severe drilling problems are
encountered in drilling wells under such contracts, we could suÅer substantial losses.
Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an
Acquisition and Thereby AÅect the Related Purchase Price.
We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203,
an anti-takeover law enacted in 1988. We have also enacted certain anti-takeover measures, including a
stockholders' rights plan. In addition, our Board of Directors has the authority to issue up to one million shares
of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences
and privileges of that stock without further vote or action by the holders of the common stock. As a result of
these measures and others, potential acquirers might Ñnd it more diÇcult or be discouraged from attempting
to eÅect 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.
14
Item 1B. Unresolved StaÅ Comments.
None.
Item 2. Properties
Our corporate headquarters are located in Snyder, Texas. We also have a number of oÇces, yards and
stockpoint facilities located in our various operating areas.
Our corporate headquarters are located at 4510 Lamesa Highway, Snyder, Texas, and our telephone
number at that address is (325) 574-6300. There are a number of improvements at our headquarters,
including:
‚ oÇce buildings with approximately 37,000 square feet of oÇce space and storage,
‚ a shop facility with approximately 7,000 square feet used for drilling equipment repairs and metal
fabrication,
‚ a truck shop facility with approximately 10,000 square feet used to maintain, overhaul and repair our
truck Öeet,
‚ a truck fabrication and rigup shop with approximately 3,000 square feet used to prepare new trucks for
service,
‚ an engine shop facility with approximately 20,000 square feet used to overhaul and repair the engines
that power our drilling rigs, and
‚ an open-ended metal storage facility with approximately 10,000 square feet.
We have regional administrative oÇces, yards and stockpoint facilities in many of the areas in which we
operate. The facilities are primarily used to support day-to-day operations, including the repair and
maintenance of equipment as well as the storage of equipment, inventory and supplies and to facilitate
administrative responsibilities and sales.
Contract Drilling Operations Ì Our drilling services are supported by several administrative oÇces and
yard facilities located throughout our areas of operations including:
‚ Texas,
‚ New Mexico,
‚ Oklahoma,
‚ Colorado,
‚ Utah,
‚ Wyoming, and
‚ Western Canada.
Pressure Pumping Ì Our pressure pumping services are supported by several oÇces and yard facilities
located throughout our areas of operations including:
‚ Pennsylvania,
‚ Ohio,
‚ West Virginia,
‚ Kentucky,
‚ Tennessee, and
‚ Wyoming.
15
Drilling and Completion Fluids Ì Our drilling and completion Öuids services are supported by several
administrative oÇces and stockpoint facilities located throughout our areas of operations including:
‚ Texas,
‚ Louisiana,
‚ New Mexico, and
‚ Oklahoma.
Oil and Natural Gas Ì Our oil and natural gas operations are supported by administrative and Ñeld
oÇces in Texas.
We own our headquarters 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.
In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County,
Texas, against our directors, alleging that the directors breached their Ñduciary duties to us as a result of
alleged failure to timely discover the embezzlement by Nelson, and against our principal accounting Ñrm,
PricewaterhouseCoopers LLP, alleging that such Ñrm committed negligence and malpractice as a result of
alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation
committee to review and inquire about these allegations and recommend our response, if any. Further legal
proceedings in these suits have been stayed pending completion of the work of the special litigation
committee. The lawsuits seek recovery on behalf of and for us and do not seek recovery from us.
We are party to various other 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 eÅect on our Ñnancial condition.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
16
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases
of Equity Securities.
(a) Market Information
Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq National Market and is
quoted under the symbol ""PTEN.'' Our common stock is included in the S&P MidCap 400 Index and several
other market indexes. The following table provides high and low sales prices of our common shares for the
periods indicated, adjusted to reÖect the two-for-one stock split on June 30, 2004:
High
Low
2005:
First quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Second quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Third quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Fourth quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004:
First quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Second quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Third quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Fourth quarter ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$26.66
29.33
36.79
36.73
$19.20
19.56
19.88
20.45
$17.15
22.38
27.79
28.45
$15.75
14.52
15.69
17.85
(b) Holders
As of March 10, 2006, there were approximately 2,174 holders of record and approximately 92,452
beneÑcial holders of our common shares.
(c) Dividends and Buyback Program
On April 28, 2004, our Board of Directors approved the initiation of a quarterly cash dividend of $0.02 on
each share of our common stock which was paid on June 2, 2004. Quarterly cash dividends in the amount of
$0.02 per share were also paid on September 1, 2004 and December 1, 2004. Total cash dividends paid in 2004
were approximately $10 million. In February 2005, our Board of Directors approved an increase in the
quarterly cash dividend on our common stock to $0.04 per share from $0.02 per share. Quarterly cash
dividends in the amount of $0.04 per share were paid on March 4, 2005, June 1, 2005, September 1, 2005 and
December 1, 2005. Total cash dividends in 2005 were approximately $27.3 million. The next quarterly cash
dividend is to be paid to holders of record on March 15, 2006 and paid on March 30, 2006. The amount and
timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend
upon business conditions, results of operations, Ñnancial conditions, terms of our credit facilities and other
factors.
On April 28, 2004, our Board of Directors authorized a two-for-one stock split in the form of a stock
dividend which was distributed on June 30, 2004.
17
The table below sets forth the information with respect to purchases of our common stock made by or on
our behalf during the quarter ended December 31, 2005.
Period covered
Total number
of shares
purchased(1)
Average price
paid per share
Total number
of shares (or
units) purchased
as part of publicly
announced plans
or programs(2)
Maximum number
(or approximate dollar
value) of shares
(or units) that may
yet be purchased under
the plans or programs(2)
October 1Ó31, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Ì
November 1Ó30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏ
355,000
December 1Ó31, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏ
Ì
Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
355,000
$ Ì
$34.23
$ Ì
$34.23
Ì
355,000
Ì
355,000
$28,518,216
$16,364,873
$16,364,873
$16,364,873
(1) All of the reported shares were purchased in open-market transactions.
(2) On June 7, 2004, our Board of Directors authorized a stock buyback program for the purchase of up to
$30 million of our outstanding common stock, which repurchases may be made from time to time as, in
the opinion of management, market conditions warrant, in the open market or in privately negotiated
transactions. On March 27, 2006, our Board of Directors increased the stock buyback program to allow
the future purchases of up to $200 million of our outstanding common stock.
(d) Securities Authorized for Issuance Under Equity Compensation Plans
Equity compensation to our employees, oÇcers and directors as of December 31, 2005 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 ReÖected
in Column(a))
(c)
Equity compensation plans approved by
security holders ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
5,449,739
$15.11
5,464,217(1)
Equity compensation plans not approved by
security holders(2) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
888,304
Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
6,338,043
$ 9.87
$14.37
Ì
5,464,217
(1) The Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (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, oÇcers 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.
18
(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 oÇcers and directors. No Incentive Stock Options
could be awarded under the 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.
19
Item 6. Selected Financial Data.
Our selected consolidated Ñnancial data as of December 31, 2005, 2004, 2003, 2002 and 2001, and for
each of the Ñve years then ended 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. The historical Ñnancial data presented
below was previously reported as restated to provide for (i) the retroactive eÅect of the merger with UTI
Energy Corp., on May 8, 2001 accounted for as a pooling of interest; (ii) the retroactive application of the
equity method of accounting for our investment in TMBR and (iii) a two-for-one stock split that occurred in
2004. The current and historical Ñnancial data presented below has been further restated to provide for, net of
related tax eÅects, (i) the eÅects of losses incurred as a result of the embezzlement and (ii) the eÅects of the
correction of other errors that are immaterial both individually and in the aggregate. See additional
information about the embezzlement and restatement in footnote (1) to the restated selected Ñnancial data
below. Certain reclassiÑcations have been made to the historical Ñnancial data to conform with the 2004
presentation.
Years Ended December 31,
2005
2004
Restated (See Note 2)
2002
2003
2001
(In thousands)
Income Statement Data:
Operating revenues:
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,485,684
93,144
122,011
39,616
1,740,455
$ 809,691
66,654
90,557
33,867
1,000,769
$639,694
46,083
69,230
21,163
776,170
$410,295
32,996
69,943
14,723
527,957
$839,931
39,600
94,456
15,988
989,975
Operating costs and expenses:
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation, depletion, amortization
and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrative ÏÏÏÏÏ
Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Merger costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Restructuring and other charges ÏÏÏÏÏÏÏ
Embezzled funds and related expensesÏÏ
Other (including gain or loss on sale of
assets) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other income (expense) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income (loss) before income taxes and
cumulative eÅect of change in
accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income tax expense (beneÑt) ÏÏÏÏÏÏÏÏÏÏÏ
Income (loss) before cumulative eÅect of
change in accounting principle ÏÏÏÏÏÏÏÏ
Cumulative eÅect of change in accounting
principle, net of related income tax
beneÑt of approximately $287 ÏÏÏÏÏÏÏÏÏ
Net income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
776,313
54,956
98,530
9,566
156,393
39,110
1,231
Ì
Ì
20,043
3,017
1,159,159
581,296
3,463
556,869
37,561
76,503
7,978
122,800
31,983
897
Ì
Ì
19,122
475,224
26,184
61,424
4,808
100,834
27,685
259
Ì
Ì
17,849
318,201
19,802
60,762
3,956
92,778
26,116
320
Ì
Ì
8,574
487,343
21,146
80,034
5,190
86,035
28,462
2,045
5,943
7,202
7,674
(1,411)
852,302
148,467
680
(4,379)
709,888
66,282
2,694
4,340
534,849
(6,892)
803
(820)
730,254
259,721
(677)
584,759
212,019
149,147
54,801
68,976
25,320
(6,089)
(1,949)
259,044
99,472
372,740
94,346
43,656
(4,140)
159,572
Ì
$ 372,740
Ì
94,346
$
(469)
$ 43,187
Ì
$ (4,140)
Ì
$159,572
20
2005
Years Ended December 31,
Restated (See Note 2)
2002
(In thousands, except per share amounts)
2004
2003
2001
2.19
$
0.57
$
0.27
$ (0.03)
$
1.04
Ì $
Ì $
Ì $
Ì $
Ì
2.19
$
0.57
$
0.27
$ (0.03)
$
1.04
2.15
$
0.56
$
0.27
$ (0.03)
$
1.01
Ì $
Ì $
Ì $
Ì $
Ì
2.15
0.16
$
$
0.56
0.06
$
$
0.26
$ (0.03)
$
1.01
Ì $
Ì $
Ì
Net income (loss) per common share:
Basic:
Income (loss) before cumulative
eÅect of change in accounting
principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cumulative eÅect of change in
accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏ
Net income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted:
Income (loss) before cumulative
eÅect of change in accounting
principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cumulative eÅect of change in
accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏ
Net income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cash dividends per common shareÏÏÏÏÏÏ
Weighted average number of common
shares outstanding:
Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
$
$
$
$
$
$
Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
173,767
170,426
166,258
169,211
161,272
157,410
152,814
164,572
157,410
158,394
Balance Sheet Data:
Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Stockholders' equityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Working capital ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,795,781
1,367,011
382,448
$1,256,785
961,501
235,480
$1,039,521
789,814
198,399
$919,374
724,248
166,885
$856,855
680,341
109,566
(1) On November 3, 2005, we announced the resignation of our CFO, Jonathan D. Nelson. On Novem-
ber 10, 2005, we announced that, based on information received by Company senior management on
November 9, 2005, the Audit Committee of our Board of Directors began an investigation into an
apparent embezzlement from us by Nelson.
On December 22, 2005, upon recommendation of Company management and the Audit Committee of
our Board of Directors, we announced that based on the results to date of the internal investigation into
the facts and circumstances surrounding the embezzlement by Nelson, we would restate previously issued
Ñnancial statements and amend our previously issued Annual Report on Form 10-K for the year ended
December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and
September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the
beneÑt of Nelson that had been recognized in our accounting records and previously issued Ñnancial
statements as payments for assets and services that we did not receive. Previously issued Ñnancial
statements have also been restated for the eÅects of the correction of other errors that are immaterial
both individually and in the aggregate. These other adjustments relate primarily to previously reported
property and equipment balances that resulted from our review of our property and equipment records
and the underlying physical assets in connection with investigation of the embezzlement. We have
restated such Ñnancial statements, and on March 17, 2006, we Ñled our amended Annual Report on Form
10-K/A and on March 27, 2006, we Ñled our amended Quarterly Reports on Form 10-Q/A with the
SEC.
21
Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating
approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was
originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one
of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson
initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent
invoices containing forged senior management approvals. This false documentation was created by Nelson to
conceal the true nature of these transactions from the Company and its independent registered public
accountants.
Nelson also instructed certain former employees, who worked under his supervision, to alter management
reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment
approval forms with forged signatures.
The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects,
beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):
From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ
$58,961
12,193
71,154
6,350
Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$77,504
(1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of
professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds
and related expenses in 2005 were $20,043,000.
The eÅects of the restatement due to the embezzlement and other adjustments on operating income as
previously reported for 2004 and prior years follow:
Years Ended December 31,
2004
2003
2002
2001
(In thousands)
Operating income (loss):
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustment for eÅects of embezzlementÏÏÏÏÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$171,214
(18,637)
(4,110)
$ 87,190
(17,375)
(3,533)
$ 3,398
(8,249)
(2,041)
$267,172
(7,461)
10
As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$148,467
$ 66,282
$(6,892)
$259,721
22
The eÅects of the restatement due to the embezzlement and other adjustments on net income as
previously reported for 2004 and prior years follow:
Years Ended December 31,
2004
2003
2002
2001
(In thousands, except per share data)
Net income (loss):
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$108,733
$ 56,419
$ 2,374
$164,162
Adjustments:
Embezzled funds expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Embezzlement amounts previously
expensed as depreciation and selling,
general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏ
Embezzlement expense, net of amounts
previously expensed ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Tax beneÑts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(19,122)
(17,849)
(8,574)
(7,674)
485
474
325
213
(18,637)
(4,110)
8,360
(17,375)
(3,533)
7,676
(8,249)
(2,041)
3,776
(7,461)
10
2,861
Net adjustmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(14,387)
(13,232)
(6,514)
(4,590)
Net income (loss) as restated ÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 94,346
$ 43,187
$(4,140)
$159,572
Net income (loss) per common share:
Basic:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustment for eÅects of embezzlementÏÏÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustment for eÅects of embezzlementÏÏÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
$
$
$
$
$
$
$
0.65
(0.07)
(0.02)
0.57
0.64
(0.07)
(0.02)
0.56
$
$
$
$
$
$
$
$
0.35
(0.07)
(0.01)
0.27
0.34
(0.07)
(0.01)
0.26
$
0.02
$ (0.03)
$ (0.01)
$ (0.03)
0.01
$
$ (0.03)
$ (0.01)
$ (0.03)
$
$
$
$
$
$
$
$
1.07
(0.03)
Ì
1.04
1.04
(0.03)
Ì
1.01
23
The eÅects of the restatement due to the embezzlement and other adjustments on selected balance sheet
data as previously reported for 2004 and prior years follow:
Total assets:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustment for eÅects of embezzlement:
Property and equipment and otherÏÏÏÏÏÏ
Income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other adjustments:
Property and equipment and otherÏÏÏÏÏÏ
Income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Stockholders' equity:
December 31,
2004
2003
2002
2001
(In thousands)
$1,322,911
$1,084,114
$942,823
$869,642
(56,133)
Ì
(56,133)
(37,496)
(1,044)
(38,540)
(20,121)
(807)
(20,928)
(11,872)
(531)
(12,403)
(9,993)
Ì
(9,993)
$1,256,785
(5,883)
(170)
(6,053)
$1,039,521
(2,350)
(171)
(2,521)
$919,374
(309)
(75)
(384)
$856,855
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustment for eÅects of embezzlementÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,007,539
(35,285)
(10,753)
$ 961,501
$ 819,749
(23,496)
(6,439)
$ 789,814
$737,731
(12,499)
(984)
$724,248
$687,142
(7,373)
572
$680,341
Working capital:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustment for eÅects of embezzlementÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
As restated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 236,957
(1,311)
(166)
$ 235,480
$ 199,613
(1,044)
(170)
$ 198,399
$167,863
(807)
(171)
$166,885
$110,172
(531)
(75)
$109,566
24
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
This Item 7 contains forward-looking statements, which are made pursuant to the ""Safe Harbor''
provisions of the Private Securities Litigation Reform Act of 1995.
The Ñnancial statements and related Ñnancial information for 2004 and all prior years presented herein
have been amended and restated on our Annual Report on Form 10-K/A for the year ended December 31,
2004, Ñled on March 17, 2006. The determination to restate these Ñnancial statements and other information
was made as a result of management's identiÑcation of an embezzlement. Further information on the
restatement can be found in Note 2 to Consolidated Financial Statements included as a part of Item 8 of this
Annual Report on Form 10-K.
Management Overview Ì 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, we provide pressure pumping services and drilling and completion Öuid
services. In addition to the aforementioned contract services, we also engage in the development, exploration,
acquisition and production of oil and natural gas. For the three years ended December 31, 2005, our operating
revenues consisted of the following (dollars in thousands):
2005
2004
2003
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,485,684
93,144
122,011
39,616
86% $ 809,691
66,654
90,557
33,867
5
7
2
81% $639,694
46,083
7
69,230
9
21,163
3
82%
6
9
3
$1,740,455
100% $1,000,769
100% $776,170
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, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South
Dakota and Western Canada while our pressure pumping services are focused primarily in the Appalachian
Basin. Our drilling and completion Öuids services are provided to operators in Texas, Southeastern New
Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. Our oil and natural gas
operations are primarily focused in West and South Texas, Southeastern New Mexico, Utah and Mississippi.
We have been a leading consolidator of the land-based contract drilling industry over the past several
years increasing our drilling Öeet to 403 rigs as of December 31, 2005. Based on publicly available information,
we believe we are the second largest owner of land-based drilling rigs in North America. Our most signiÑcant
transaction occurred in May 2001 when we merged with UTI Energy Corp. in a merger of equals which
basically doubled our drilling Öeet and added the pressure pumping services business. Growth by acquisition
has been a corporate strategy intended to expand both revenues and proÑts.
The proÑtability of our business is most readily assessed by two primary indicators: our average number of
rigs operating and our average revenue per operating day. During 2005, our average number of rigs operating
increased to 276 from 211 in 2004 and our average revenue per operating day increased to $14,770 from
$10,470 in 2004. Primarily due to these improvements, we experienced an increase of approximately
$278 million, or 295%, in consolidated net income in 2005.
Our revenues, proÑtability and cash Öows are highly dependent upon the market prices of oil and natural
gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas
operators tend to expand, which results in increased demand for our contract services. Conversely, in periods
of time when these commodity prices deteriorate, the demand for our contract services generally weakens and
we experience downward pressure on pricing for our services. In addition, our operations are highly impacted
by competition, the availability of excess equipment, labor issues and various other factors which are more
fully described as risk factors contained in Item 1A of this Report.
25
Management believes that the liquidity of our balance sheet as of December 31, 2005, which includes
approximately $382 million in working capital (including $136 million in cash), no long term debt and
$144 million available under a $200 million line of credit (availability of $56 million is reserved for
outstanding letters of credit) provides us with the ability to pursue acquisition opportunities, expand into new
regions, make improvements to our assets and survive downturns in our industry.
Embezzlement and Restatements Ì On November 3, 2005, we announced the resignation of our CFO,
Jonathan D. Nelson. On November 10, 2005, we announced that, based on information received by Company
senior management on November 9, 2005, the Audit Committee of our Board of Directors began an
investigation into an apparent embezzlement from us by Nelson.
On December 22, 2005, upon recommendation of Company management and the Audit Committee of
our Board of Directors, we announced that based on the results to date of the internal investigation into the
facts and circumstances surrounding the embezzlement by Nelson, we would restate previously issued
Ñnancial statements and amend our previously issued Annual Report on Form 10-K for the year ended
December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and
September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the
beneÑt of Nelson that had been recognized in our accounting records and previously issued Ñnancial
statements as payments for assets and services that we did not receive. Previously issued Ñnancial statements
have also been restated for the eÅects of the correction of other errors that are immaterial both individually
and in the aggregate. These other adjustments relate primarily to previously reported property and equipment
balances that resulted from our review of our property and equipment records and the underlying physical
assets in connection with investigation of the embezzlement. We have restated such Ñnancial statements, and
on March 17, 2006, we Ñled our amended Annual Report on Form 10-K/A and on March 27, 2006, we Ñled
our amended Quarterly Reports on Form 10-Q/A with the SEC.
Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating
approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was
originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one
of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson
initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent
invoices containing forged senior management approvals. This false documentation was created by Nelson to
conceal the true nature of these transactions from the Company and its independent registered public
accountants.
Nelson also instructed certain former employees, who worked under his supervision, to alter management
reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment
approval forms with forged signatures.
The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects,
beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):
From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ
$58,961
12,193
71,154
6,350
Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$77,504
(1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of
professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds
and related expenses in 2005 were $20,043,000.
Commitments and Contingencies Ì We maintain letters of credit in the aggregate amount of approxi-
mately $56 million for the beneÑt 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
26
letters of credit expire at various times during each calendar year. No amounts have been drawn under the
letters of credit.
We have signed non-cancelable commitments to purchase $118 million of equipment to be received
throughout 2006.
Net income for the years ended December 31, 2005, 2004 and 2003 include embezzled funds and related
expenses of $20.0 million, $19.1 million and $17.8 million, respectively. On November 16, 2005, the SEC
obtained a freeze order on Nelson's assets (including assets held by entities controlled by him) and a Receiver
was appointed to collect those assets. The Company understands that the Receiver will ultimately liquidate
the assets and propose a plan to distribute the proceeds. While the Company believes it has a claim for at least
the full amount embezzled, other creditors have or may assert claims on the assets held by the Receiver. As a
result, recovery by the Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if
any, will be recognized when they are considered collectable. Net income for the year ended December 31,
2002, includes a charge of $4.7 million related to the Ñnancial failure in 2002 of a workers' compensation
insurance carrier that had provided coverage for us in prior years. Net income for the year ended
December 31, 2005, includes a charge of $4.2 million to increase this reserve.
In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County,
Texas, against our directors, alleging that the directors breached their Ñduciary duties to us as a result of
alleged failure to timely discover the embezzlement. The Board of Directors formed a special litigation
committee to review and inquire about these allegations and recommend our response, if any. Further legal
proceedings in these suits have been stayed pending completion of the work of the special litigation
committee. The lawsuits seek recovery on behalf of and for us and do not seek recovery from us.
Trading and investing Ì 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, money markets and highly rated municipal and commercial bonds.
Description of business Ì We conduct our contract drilling operations in Texas, New Mexico,
Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and
Western Canada. As of December 31, 2005, we owned 403 drilling rigs. We provide pressure pumping services
to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well
stimulation and cementing for completion of new wells and remedial work on existing wells. We provide
drilling Öuids, completion Öuids and related services to oil and natural gas operators in Texas, Southeastern
New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. Drilling and completion
Öuids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil
and natural gas wells. We are also engaged in the development, exploration, acquisition and production of oil
and natural gas. Our oil and natural gas operations are focused primarily in producing regions in West and
South Texas, Southeastern New Mexico, Utah and Mississippi.
The North American land drilling industry has experienced many downturns 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 diÇculty sustaining proÑt margins during the downturn
periods.
In addition to adverse eÅects that future declines in demand could have on us, ongoing factors which
could adversely aÅect utilization rates and pricing, even in an environment of stronger oil and natural gas
prices and increased drilling activity, include:
‚ movement of drilling rigs from region to region,
‚ reactivation of land-based drilling rigs, and
‚ new construction of drilling rigs.
We cannot predict either the future level of demand for our contract drilling services or future conditions
in the oil and natural gas contract drilling business.
27
Critical Accounting Policies
In addition to established accounting policies, our consolidated Ñnancial 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 Ì 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 assets for impairment when events or changes in circumstances
indicate that the carrying values of certain assets either exceed their respective fair values or may not be
recovered over their estimated remaining useful lives. The cyclical nature of our industry has resulted in
Öuctuations in rig utilization over periods of time. Management believes that the contract drilling industry will
continue to be cyclical and rig utilization will Öuctuate. Based on management's expectations of future trends,
we estimate future cash Öows in our assessment of impairment assuming the following four-year industry
cycle: one year projected with low utilization, one year projected as a recovery period with improving
utilization and the remaining two years projecting higher utilization. Provisions for asset impairment are
charged to income when estimated future cash Öows, on an undiscounted basis, are less than the asset's net
book value. Impairment charges are recorded based on discounted cash Öows. There were no impairment
charges to property and equipment during the years 2005, 2004 or 2003.
Oil and natural gas properties Ì Oil and natural gas properties are accounted for using the successful
eÅorts method of accounting. Under the successful eÅorts 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. In accordance with Statement of Financial Accounting
Standards No. 19, ""Financial Accounting and Reporting by Oil and Gas Producing Companies,''
(""SFAS No. 19'') 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 the related reserve classiÑcation. If
the reserve classiÑcation is uncertain after one year following the completion of drilling, we consider the costs
of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including
seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The
capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well
equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized
on the units-of-production method, based on engineering estimates of proved oil and natural gas reserves of
each respective Ñeld. We review our proved oil and natural gas properties for impairment when an event
occurs such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved
properties are grouped by Ñeld and undiscounted cash Öow estimates are provided by an independent
petroleum engineer. If the net book value of a Ñeld exceeds its undiscounted cash Öow estimate, impairment
expense is measured and recognized as the diÅerence between its net book value and discounted cash Öow.
Unproved oil and natural gas properties are reviewed quarterly to determine impairment. Our intent to drill,
lease expiration and abandonment of area are considered. Assessment of impairment is made on a lease-by-
lease basis. If an unproved property is determined to be impaired, then costs related to that property are
expensed. Impairment expense of approximately $4.4 million, $3.2 million and $1.4 million for the years ended
December 31, 2005, 2004 and 2003, respectively, is included in depreciation, depletion and impairment in the
accompanying Ñnancial statements.
Goodwill Ì Goodwill is considered to have an indeÑnite useful economic life and is not amortized. As
such, we assess impairment of our goodwill annually or on an interim basis if events or circumstances indicate
that the fair value of the asset has decreased below its carrying value.
28
Revenue recognition Ì 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, as described below. We follow the percentage-of-completion method of accounting for
footage contract drilling arrangements. Under the percentage-of-completion method, management estimates
are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the
nature of turnkey contract drilling arrangements and risks therein, we follow the completed contract method of
accounting for such arrangements. Under this method, revenues and expenses related to a well in progress are
deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process
wells are made when estimated total expenses are expected to exceed estimated total revenues.
In accordance with Emerging Issues Task Force Issue No. 00-14, we recognize reimbursements received
from third parties for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as
direct costs.
Use of estimates Ì The preparation of Ñnancial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make certain estimates and
assumptions that aÅect the reported amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the Ñnancial statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could diÅer from such estimates.
Key estimates used by management include:
‚ allowance for doubtful accounts,
‚ total expenses to be incurred on footage and turnkey drilling contracts,
‚ depreciation and depletion,
‚ asset impairment,
‚ reserves for self-insured levels of insurance coverages, and
‚ fair values of assets and liabilities assumed in acquisitions.
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.
Related Party Transactions
We operate certain oil and natural gas properties in which certain of our aÇliated persons have
participated, either individually or through entities they control, in the prospects or properties in which we
have an interest. These participations, which have been on a working interest basis, have been in prospects or
properties we originated or acquired. At December 31, 2005, aÇliated persons were working interest owners in
254 of 305 total wells we operated. We make sales of working interests to reduce our economic risk in the
properties. Generally, it is more eÇcient for us to sell the working interests to these aÇliated persons than to
market them to unrelated third parties. Sales of working interests were made at cost, including our costs of
acquiring and preparing the working interests for sale. These costs were paid by the working interest owners on
a pro rata basis based upon their working interest ownership percentage. The price at which working interests
were sold to aÇliated persons was the same price at which working interests were sold to unaÇliated persons.
Production revenues and joint interest costs of each of the aÇliated persons during 2005 for all wells
operated by us in which the aÇliated persons have working interests are presented in the table below. These
amounts do not necessarily represent their proÑts or losses from these interests because the joint interest costs
do not include the parties' related drilling and leasehold acquisition costs incurred prior to January 1, 2005.
These activities resulted in a payable to the aÇliated persons of approximately $1.5 million and $1.2 million
29
and a receivable from the aÇliated persons of approximately $1.2 million and $856,000 at December 31, 2005
and 2004, respectively.
Name
Cloyce A. Talbott ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Anita Talbott(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Jana Talbott, Executrix to the Estate of Steve Talbott(3) ÏÏÏÏÏÏÏÏÏÏ
Stan Talbott(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
John Evan Talbott Trust(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Lisa Beck and Stacy Talbott(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
SSI Oil & Gas, Inc.(4) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
IDC Enterprises, Ltd.(5) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Year Ended
December 31, 2005
Production
Revenues(1)
$
195,491
88,824
19,373
7,639
3,725
1,158,657
210,825
13,432,098
Joint
Interest
Costs(2)
$
49,668
21,389
2,871
3,163
987
492,839
97,152
8,460,393
SubtotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
15,116,632
9,128,462
A. Glenn Patterson ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Robert Patterson(6) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Thomas M. Patterson(6) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
SubtotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Jonathan D. Nelson, former Chief Financial OÇcer ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
122,348
7,719
7,719
137,786
290,506
29,075
4,396
4,396
37,867
381,506
Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$15,544,924
$9,547,835
(1) Revenues for production of oil and natural gas, net of state severance taxes.
(2) Includes leasehold costs, tangible equipment costs, intangible drilling costs and lease operating expense
billed during that period. All joint interest costs have been paid on a timely basis.
(3) Anita Talbott is the wife of Cloyce A. Talbott. Stan Talbott, Lisa Beck and Stacy Talbott are
Mr. Talbott's adult children. Steve Talbott is the deceased son of Mr. Talbott. John Evan Talbott is
Mr. Talbott's grandson.
(4) SSI Oil & Gas, Inc. is beneÑcially owned 50% by Cloyce A. Talbott and directly owned 50% by A. Glenn
Patterson.
(5) IDC Enterprises, Ltd. is 50% owned by Cloyce A. Talbott and 50% owned by A. Glenn Patterson.
(6) Robert and Thomas M. Patterson are A. Glenn Patterson's adult children.
In 2005, 2004 and 2003, we paid approximately $424,000, $914,000 and $740,000, respectively, to TMP
Truck and Trailer LP (""TMP''), during the period it was owned by Thomas M. Patterson (son of A. Glenn
Patterson), for certain equipment and metal fabrication services. Purchases from TMP were at current market
prices.
In 2005 and 2004, we paid approximately $273,000 and $39,000, respectively, to Melco Services
(""Melco'') for dirt contracting services and $59,000 and $44,000, respectively, to L&N Transportation
(""L&N'') for water hauling services. Both entities are owned by Lance D. Nelson, brother of Jonathan D.
Nelson. Purchases from Melco and L&N were at current market prices.
See Note 2 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report for
information pertaining to fraudulent payments made to or for the beneÑt of Jonathan D. Nelson, our former
CFO.
30
Liquidity and Capital Resources
As of December 31, 2005, we had working capital of $382 million including cash and cash equivalents of
$136 million. For 2005, our sources of cash Öow included:
‚ $460 million from operations,
‚ $43 million from the exercise of stock options, and
‚ $13 million from sales of property and equipment.
We used $74 million to purchase land drilling assets from Key Energy Services, Inc. and six additional
land-based drilling rigs, $27 million to pay dividends on our common stock, $12 million to buy 355,000 shares
of our common stock pursuant to the stock buyback program authorized by our Board of Directors on June 7,
2004 and $380 million:
‚ to make capital expenditures for the betterment and refurbishment of our drilling rigs,
‚ to acquire and procure drilling equipment,
‚ to fund capital expenditures for our pressure pumping and drilling and completion Öuids divisions, and
‚ to fund leasehold acquisition and exploration and development of oil and natural gas properties.
As of December 31, 2005, $400,000 of cash was pledged as collateral for losses which could become
payable under the terms of our workers' compensation insurance contracts and was therefore restricted as to
use.
In January 2005, we purchased land drilling assets of Key Energy Services, Inc. for $61.8 million. The
assets acquired included 25 active and 10 stacked land-based drilling rigs, related drilling equipment, yard
facilities and a rig moving Öeet consisting of approximately 45 trucks and 100 trailers. In June 2005, we
acquired one land-based drilling rig for $3.6 million. In September 2005, we acquired Ñve land-based drilling
rigs and related drilling equipment for $8.2 million. The transactions were accounted for as acquisitions of
asset and the respective purchase prices were allocated among the assets acquired based on their estimated fair
market values.
We replaced our prior credit facility in December 2004 with a Ñve-year, $200 million unsecured revolving
line of credit (""LOC''). Interest is to be paid on outstanding LOC balances at a Öoating rate ranging from
LIBOR plus 0.625% to 1.0% or the prime rate. This arrangement includes various fees, including a
commitment fee on the average daily unused amount (0.15% at December 31, 2005). There are customary
restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to
capitalization ratio and a minimum interest coverage ratio. We do not expect that the restrictions and
covenants will restrict our ability to operate or react to opportunities that might arise. Availability under the
LOC is reduced by outstanding letters of credit which totaled $56 million at December 31, 2005. There were
no outstanding borrowings under the LOC at December 31, 2005.
In February 2005, our Board of Directors approved an increase in the quarterly cash dividend on our
common stock to $0.04 per share from $0.02 per share. The next quarterly cash dividend is to be paid to
holders of record on March 15, 2006 and paid on March 30, 2006.
On June 7, 2004, our Board of Directors authorized a stock buyback program for the purchase of up to
$30 million of our outstanding common stock. During the second quarter of 2004, we purchased
100,000 shares of our common stock in the open market for approximately $1.5 million (adjusted to reÖect the
two-for-one stock split on June 30, 2004). During the fourth quarter of 2005, we purchased 355,000 shares of
our common stock in the open market for approximately $12.2 million. These shares are included in treasury
stock. On March 27, 2006, our Board of Directors increased the stock buyback program to allow the future
purchases of up to $200 million of our outstanding common stock.
We believe that the current level of cash and short-term investments, together with cash generated from
operations, should be suÇcient to meet our capital needs. From time to time, acquisition opportunities are
31
evaluated. The timing, size or success of any acquisition and the associated capital commitments are
unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy
these needs through a combination of working capital, cash generated from operations, our existing credit
facility and additional debt Ñnancing or equity Ñnancing. However, there can be no assurance that such capital
would be available.
Results of Operations
Comparison of the years ended December 31, 2005 and 2004
A summary of operations by business segment for the years ended December 31, 2005 and 2004 follows:
Contract Drilling
Years Ended December 31,
Restated
(See Note 2)
2004
% Change
2005
(Dollars in thousands)
RevenuesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating days ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average revenue per operating day ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average direct operating costs per operating dayÏÏÏÏÏÏÏÏÏ
Number of owned rigs at end of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average number of rigs owned during periodÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operatingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Rig utilization percentage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,485,684
$ 776,313
$
5,069
$ 131,740
$ 572,562
100,591
14.77
7.72
403
397
276
$
$
69%
$809,691
$556,869
$
4,417
$101,779
$146,626
77,355
10.47
7.20
361
359
211
59%
$
$
$ 329,073
$140,945
83.5%
39.4%
14.8%
29.4%
290.5%
30.0%
41.1%
7.2%
11.6%
10.6%
30.8%
16.9%
133.5%
The market price of natural gas remained high in 2005. In fact, the average market price of natural gas
improved to $8.98 per Mcf in 2005 compared to $5.95 per Mcf in 2004, resulting in an increase in demand for
our contract drilling services. Our average number of rigs operating increased to 276 in 2005 from 211 in 2004.
The average market price of natural gas and our average rigs operating for each of the Ñscal quarters in 2005
and 2004 follow:
1st
Quarter
2nd
Quarter
3rd
Quarter
4th
Quarter
2005:
Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004:
Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$6.62
263
$5.64
197
$7.14
265
$6.13
203
$9.82
283
$5.62
216
$12.64
292
$ 6.42
229
Revenues and direct operating costs increased as a result of the increased number of operating days, as
well as an increase in the average revenue and average direct operating costs per operating day. Operating days
and average rigs operating increased as a result of the increased demand for our contract drilling services, the
acquisition of land drilling assets from Key Energy Services, Inc. in January 2005 and activation of refurbished
stacked rigs. Average revenue per operating day increased as a result of increased demand and pricing for our
drilling services. SigniÑcant capital expenditures were incurred during 2005 to activate additional drilling rigs
to meet increased demand, to modify and upgrade our existing drilling rigs and to acquire additional related
equipment such as drill pipe, drill collars, engines, Öuid circulating systems, rig hoisting systems and safety
32
enhancement equipment. Increased depreciation expense in 2005 was due to acquisitions and capital
expenditures in 2004 and 2005.
Pressure Pumping
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total jobs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average direct operating costs per jobÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2005
% Change
Years Ended December 31,
2004
(Dollars in thousands)
$66,654
$37,561
$ 7,234
$ 5,112
$16,747
7,444
8.95
$
$
5.05
$17,705
$93,144
$54,956
$ 9,430
$ 7,094
$21,664
9,615
9.69
$
$
5.72
$25,508
39.7%
46.3%
30.4%
38.8%
29.4%
29.2%
8.3%
13.3%
44.1%
Revenues and direct operating costs for our pressure pumping operations increased as a result of the
increased number of jobs, as well as an increase in the average revenue and average direct operating costs per
job. The increase in jobs in 2005 was largely due to our expanded operations in the Appalachian regions of
Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the
improved industry conditions as discussed in ""Contract Drilling'' above. Increased average revenue per job was
due primarily to increased pricing for our services. Selling, general and administrative expenses increased
largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation
expense during 2005 was largely due to the expansion of the pressure pumping segment from 2003 through
2005 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures
increased in 2005 compared to 2004 due to further expansion of services into Tennessee and Wyoming as well
as modiÑcations and upgrades to existing equipment and facilities.
Drilling and Completion Fluids
2005
% Change
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total jobsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average direct operating costs per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Years Ended December 31,
Restated
(See Note 2)
2004
(Dollars in thousands)
$90,557
$76,503
$ 7,696
$ 2,156
$ Ì
$ 4,202
2,205
$ 41.07
$ 34.70
$ 1,488
$122,011
$ 98,530
8,912
$
2,368
$
$
254
$ 11,947
1,980
61.62
49.76
3,042
$
$
$
34.7%
28.8%
15.8%
9.8%
N/A%
184.3%
(10.2)%
50.0%
43.4%
104.4%
Revenues and direct operating costs increased as a result of an increase in the average revenue and direct
operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an
increase in the size of our oÅshore jobs. Selling, general and administrative expense increased primarily due to
increased incentive compensation resulting from higher proÑtability levels. Other expense from operations
33
includes a charge of $254,000 representing the deductible portion of the Company's insurance coverage for
damage caused by the hurricanes in August and September 2005.
Oil and Natural Gas Production and Exploration
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average net daily oil production (Bbls) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average net daily gas production (Mcf) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average oil sales price (per Bbl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average gas sales price (per Mcf)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2005
% Change
Years Ended December 31,
2004
(Dollars in thousands)
$33,867
$ 7,978
$ 1,816
$13,309
$10,764
$14,451
1,071
7,429
$ 39.12
5.81
$
$39,616
$ 9,566
$ 2,189
$14,456
$13,405
$17,163
860
7,016
$ 54.30
7.64
$
17.0%
19.9%
20.5%
8.6%
24.5%
18.8%
(19.7)%
(5.6)%
38.8%
31.5%
Revenues increased due to increased market prices for oil and natural gas. Direct operating costs
increased as a result of higher oilÑeld service cost and production taxes. Average net daily oil production
decreased as a result of production declines and the sale of certain oil properties during 2005. Average net
daily gas production also decreased as a result of the sale of certain natural gas properties, however, this
decrease was partially oÅset by an increase in production. Depreciation, depletion and impairment expense
includes approximately $4.4 million and $3.2 million of expenses incurred during 2005 and 2004, respectively,
to impair certain oil and natural gas properties.
Corporate and Other
2005
% Change
Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other operating (including gain or loss on sale of assets)ÏÏÏÏ
Embezzled funds and related expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Interest income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Years Ended December 31,
Restated
(See Note 2)
2004
(Dollars in thousands)
$10,820
897
$
$
444
$(1,411)
$19,122
$ 1,140
695
$
235
$
$ Ì
$13,510
$ 1,231
$
735
$ 2,763
$20,043
$ 3,551
516
$
428
$
$ 5,308
24.9%
37.2%
65.5%
N/A%
4.8%
211.5%
(25.8)%
82.1%
N/A%
Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to
the exercise of employee stock options, increased professional fees and additional compensation expense
related to the issuance of restricted shares to certain key employees in 2004 and 2005. Embezzled funds and
related expenses includes fraudulent payments made to or for the beneÑt of Jonathan D. Nelson, our former
CFO, for assets and services that were not received by the Company and professional fees and expenses
incurred as a result of the embezzlement. Other expense from operations in 2005 includes a charge of
$4.2 million to increase reserves related to the Ñnancial failure of a workers' compensation insurance carrier
used previously by the Company.
34
Comparison of the years ended December 31, 2004 and 2003
A summary of operations by business segment for the years ended December 31, 2004 and 2003 follows:
Contract Drilling
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating days ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average revenue per operating day ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average direct operating costs per operating day ÏÏÏÏÏÏÏÏÏÏÏÏ
Number of owned rigs at end of periodÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average number of rigs owned during period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operating ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Rig utilization percentage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
% Change
2004
Restated (See Note 2)
Years Ended December 31,
2003
(Dollars in thousands)
$639,694
$475,224
$
4,401
$ 87,255
$ 72,814
68,798
9.30
6.91
343
336
188
56%
$809,691
$556,869
$
4,417
$101,779
$146,626
77,355
10.47
7.20
361
359
211
59%
$
$
$
$
$140,945
$ 77,350
26.6%
17.2%
0.4%
16.6%
101.4%
12.4%
12.6%
4.2%
5.2%
6.8%
12.2%
5.4%
82.2%
The market price of natural gas remained high in 2004. In fact, the average market price of natural gas
improved to $5.95 per Mcf in 2004 compared to $5.45 per Mcf in 2003, resulting in an increase in demand for
our contract drilling services. Our average number of rigs operating increased to 211 in 2004 from 188 in 2003.
The average market price of natural gas and our average rigs operating for each of the Ñscal quarters in 2004
and 2003 follow:
1st
Quarter
2nd
Quarter
3rd
Quarter
4th
Quarter
2004:
Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operatingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003:
Average natural gas price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average rigs operatingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$5.64
197
$5.91
176
$6.13
203
$5.70
195
$5.62
216
$4.88
192
$6.42
229
$5.29
191
Revenues and direct operating costs increased as a result of the increased number of operating days, as
well as an increase in the average revenue and direct operating costs per operating day in 2004. Average
revenue per operating day increased as a result of increased demand and pricing for our contract drilling
services. SigniÑcant capital expenditures were incurred during 2004 to activate additional drilling rigs to meet
increased demand, to modify and upgrade our existing drilling rigs and to acquire additional related equipment
such as drill pipe, drill collars, engines, Öuid circulating systems, rig hoisting systems and safety enhancement
35
equipment. Increased depreciation expense in 2004 was due primarily to capital expenditures in 2003 and
2004, as well as acquisitions.
Pressure Pumping
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total jobs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average direct operating costs per jobÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004
% Change
Years Ended December 31,
2003
(Dollars in thousands)
$46,083
$26,184
$ 5,683
$ 3,774
$10,442
5,667
8.13
$
$
4.62
$10,524
$66,654
$37,561
$ 7,234
$ 5,112
$16,747
7,444
8.95
$
$
5.05
$17,705
44.6%
43.5%
27.3%
35.5%
60.4%
31.4%
10.1%
9.3%
68.2%
Revenues and direct operating costs for our pressure pumping operations increased as a result of the
increased number of jobs, as well as an increase in the average revenue and average direct operating costs per
job. The increase in jobs in 2004 was largely due to our expanded operations in the Appalachian regions of
Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the
improved industry conditions as discussed in ""Contract Drilling'' above. Increased average revenue per job was
due primarily to increased pricing for our services. Selling, general and administrative expenses increased
largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation
expense during 2004 was largely due to the expansion of the pressure pumping segment during 2004 and 2003
and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures
increased in 2004 compared to 2003 due to further expansion of services into Tennessee and Wyoming as well
as modiÑcations and upgrades to existing equipment and facilities.
Drilling and Completion Fluids
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total jobs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average revenue per job ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average direct operating costs per jobÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004
% Change
Years Ended December 31,
Restated (See Note 2)
2003
(Dollars in thousands)
30.8%
$69,230
24.5%
$61,424
3.3%
$ 7,447
$ 2,279
(5.4)%
$(1,920) N/A%
14.2%
14.6%
9.1%
63.2%
1,931
$ 35.85
$ 31.81
912
$
$90,557
$76,503
$ 7,696
$ 2,156
$ 4,202
2,205
$ 41.07
$ 34.70
$ 1,488
The number of jobs increased as a result of the improved industry conditions as discussed in ""Contract
Drilling'' above, as well as increased drilling activity in the Gulf of Mexico. Revenues and direct operating
costs increased in 2004 primarily as a result of the increased number of jobs, as well as an increase in the
36
average revenue and direct operating costs per job. Average revenue and direct operating costs per job
increased primarily as a result of an increase in the number of larger jobs completed in the Gulf of Mexico.
Oil and Natural Gas Production and Exploration
Revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Direct operating costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Capital expendituresÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average net daily oil production (Bbls) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average net daily gas production (Mcf) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average oil sales price (per Bbl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Average gas sales price (per Mcf)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
% Change
2004
Years Ended December 31,
2003
(Dollars in thousands)
$21,163
$ 4,808
$ 1,489
$ 7,082
$ 7,784
$10,015
788
5,656
$ 30.54
4.97
$
$33,867
$ 7,978
$ 1,816
$13,309
$10,764
$14,451
1,071
7,429
$ 39.12
5.81
$
60.0%
65.9%
22.0%
87.9%
38.3%
44.3%
35.9%
31.3%
28.1%
16.9%
Oil and gas revenues and direct operating costs increased in 2004 compared to 2003, primarily due to the
oil and natural gas properties acquired in the acquisition of TMBR during February 2004 and increased
market prices received for oil and natural gas during 2004. Direct operating costs further increased as a result
of approximately $600,000 of dry hole costs incurred during 2004. Depreciation, depletion and impairment
expense increased in 2004 primarily as a result of increased production and an increase of approximately
$1.8 million of expenses incurred to impair certain oil and natural gas properties.
Corporate and Other
Selling, general and administrativeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other operating (including gain or loss on sale of assets) ÏÏÏÏÏÏ
Embezzled funds expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Interest incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
% Change
2004
Years Ended December 31,
Restated (See Note 2)
2003
(Dollars in thousands)
$ 8,665
259
$
$
444
$(4,379)
$17,849
$ 1,116
$
292
$ 1,870
$10,820
897
$
$
444
$(1,411)
$19,122
$ 1,140
695
$
235
$
24.9%
246.3%
Ì%
67.8%
7.1%
2.2%
138.0%
(87.4)%
Selling, general and administrative expenses increased primarily as a result of increased professional
expenses (including expenses incurred during 2004 to comply with the requirements of Section 404 of the
Sarbanes-Oxley Act of 2002) and additional compensation expense related to the issuance of restricted shares
to certain key employees. Embezzled funds expense includes fraudulent payments made to or for the beneÑt of
Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company. Interest
expense in 2004 included approximately $445,000 of termination fees and other related charges incurred as a
result of the replacement of our credit facility. Restructuring and other charges in 2003 includes a $2.5 million
payment received as settlement for contract drilling services previously provided in Mexico by our wholly-
owned subsidiary, Norton Drilling Company Mexico, Inc. The receivable had been reserved as uncollectible at
the time of our acquisition of Norton Drilling Company Mexico, Inc. in 1999. Other income in 2003 includes
approximately $1.7 million representing our pro rata share of the net income of TMBR using the equity
method of accounting.
37
Income Taxes
Years Ended December 31,
Restated (See Note 2)
Income before income tax ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income tax expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
EÅective tax rateÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003
2005
2004
(Dollars in thousands)
$149,147
54,801
$584,759
212,019
$68,976
25,320
36.3%
36.7%
36.7%
The signiÑcance of the impact of the permanent diÅerences to our eÅective income tax rate in 2005 was
largely attributable to the new Domestic Production Activities Deduction. The deduction was enacted as part
of the American Jobs Creation Act of 2004 eÅective for taxable years after December 31, 2004. The act allows
a deduction of 3% in 2005 or 2006, 6% in 2007, 2008 or 2009, and 9% 2010 and after on the lesser of qualiÑed
production activities income or taxable income. Our eÅective income tax rate of 36.7% for 2004 and 2003 is
primarily attributable to a Federal rate of 35.0% and state income tax rates of 1.6% and 1.5%, respectively. The
impact of permanent diÅerences was not signiÑcant in 2004 or 2003.
For tax purposes, we have available at December 31, 2005, Federal net operating loss carryforwards of
approximately $11 million and $118,000 of alternative minimum tax credit carryforwards. These carryforwards
are attributable to the acquisition of TMBR in February 2004.
The net operating loss carryforwards, if unused, are scheduled to expire as follows: 2006 Ì $1 million,
2011 Ì $2 million, 2018 Ì $4 million and 2019 Ì $4 million. The alternative minimum tax credit may be
carried forward indeÑnitely.
We record deferred Federal income taxes based primarily on the relationship between the amount of our
unused Federal net operating loss carryforwards and the temporary diÅerences between the book basis and tax
basis in 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 diÅerences are expected to be settled. As a result of fully
recognizing the beneÑt of our deferred income taxes, we incur deferred income tax expense as these beneÑts
are utilized. We incurred deferred income tax expense of approximately $17.1 million, $14.8 million and
$10.0 million for 2005, 2004 and 2003, respectively.
Volatility of Oil and Natural Gas Prices
Our revenue, proÑtability and rate of growth are substantially dependent upon prevailing prices for oil and
natural gas, with respect to all of our operating segments. For many years, oil and natural gas prices and
markets have been volatile. Prices are aÅected 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. Natural gas prices fell from an average of $6.23 per Mcf in
the Ñrst quarter of 2001 to an average of $2.51 per Mcf for the same period in 2002. During this same period,
the average number of our rigs operating dropped by approximately 50%. The average market price of natural
gas improved from $3.36 in 2002 to and $8.98 in 2005, resulting in an increase in demand for our drilling
services. Our average number of rigs operating increased from 126 in 2002 to 276 in 2005. We expect oil and
natural gas prices to continue to be volatile and to aÅect our Ñnancial condition and operations and ability to
access sources of capital. A signiÑcant decrease in expected market prices for natural gas could result in a
material decrease in demand for drilling rigs and reduction in our operation results.
The North American land drilling industry has experienced many downturns 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 diÇculty sustaining proÑt margins during the downturn
periods.
38
Impact of InÖation
We believe that inÖation will not have a signiÑcant near-term impact on our Ñnancial position.
Recently-Issued Accounting Standards
The Financial Accounting standards Board (""FASB'') issued StaÅ Position FIN 47, Accounting for
Conditional Asset Retirement Obligations (""FIN 47''), an interpretation of FASB Statement No. 143, in
March 2005. The statement clariÑes the term ""conditional asset retirement obligation'' as used in FASB 143.
The provisions of FIN 47, which the Company adopted on December 31, 2005, did not have a material impact
on the Company's Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based
Payment (""SFAS 123(R)'') in December 2004; it replaces FASB Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), companies would have
been required to implement the standard as of the beginning of the Ñrst interim reporting period that begins
after June 15, 2005. However, in April 2005, the SEC announced the adoption of an Amendment to
Rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R) that amends the
compliance dates and allows companies to implement SFAS 123(R) beginning with the Ñrst annual reporting
period beginning on or after June 15, 2005. The Company intends to adopt SFAS 123(R) on January 1, 2006.
We currently use the intrinsic value method to value stock options, and accordingly, no compensation
expense has been recognized for stock options since we grant stock options with exercise prices equal to our
common stock market price on the date of the grant. SFAS 123(R) requires the expensing of all stock-based
compensation, including stock options and restricted shares, using the fair value method. We intend to expense
stock options using the ModiÑed Prospective Transition method as described in SFAS 123(R). This method
will require expense to be recognized for stock options over their respective remaining vesting periods. No
expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R). We are
evaluating the impact of the adoption of SFAS 123(R) on our results of operations and Ñnancial position.
Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs Ì an amend of
ARB No. 43, Chapter 4 (""SFAS 151''). SFAS 151 is eÅective, and will be adopted, for inventory costs
incurred during Ñscal years beginning after June 15, 2005 and is to be applied prospectively. SFAS 151
amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to require current period recognition of
abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Adoption is
not expected to have a material eÅect on our Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary
Assets Ì an amendment of APB Opinion No. 29 (""SFAS 153''). FAS 153 is eÅective, and will be adopted,
for nonmonetary asset exchanges occurring in Ñscal periods beginning after June 15, 2005 and is to be applied
prospectively. SFAS 153 eliminates the exception for fair value treatment of nonmonetary exchanges of
similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do
not have commercial substance. A nonmonetary exchange has commercial substance if the future cash Öows
of the entity are expected to change signiÑcantly as a result of the exchange. Adoption is not expected to have
a material eÅect on our Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting standards No. 154, Accounting changes and Error
Corrections Ì a replacement of APB Opinion No. 20 and FASB Statement No. 3 (""SFAS 145''). SFAS 154
is eÅective, and will be adopted for accounting changes made in Ñscal years beginning after December 15,
2005 and is to be applied retrospectively. SFAS 154 requires that retroactive application of a change in
accounting principle be limited to the direct eÅects of the change. Adoption is not expected to have a material
eÅect on the Company's Ñnancial position or results of operations.
39
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We currently have no exposure to interest rate market risk as we have no outstanding balance under our
credit facility. Should we incur a balance in the future, we would have exposure associated with the Öoating
rate of the interest charged on that balance. The revolving credit facility calls for periodic interest payments at
a Öoating rate ranging from LIBOR plus 0.625% to 1.0% or at the prime rate. The applicable rate above
LIBOR is based upon our debt to capitalization ratio. Our exposure to interest rate risk due to changes in
LIBOR is not expected to be material.
We conduct some business in Canadian dollars through our Canadian land-based drilling operations. The
exchange rate between Canadian dollars and U.S. dollars has Öuctuated 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.
Item 8. Financial Statements and Supplementary Data.
Financial Statements are Ñled 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.
Background to the Fraud and Restatement
In November 2005, the Company discovered that its former Chief Financial OÇcer, Jonathan D. Nelson
(""Nelson''), had fraudulently diverted approximately $78 million in Company funds for his own beneÑt.
Nelson's fraudulent diversions began in 1998 and continued until the fourth quarter of 2005 when he resigned
from the Company. The funds fraudulently diverted were recorded as payments for assets or services that were
not actually received by the Company.
Beginning in 1998, and continuing until late 2000, Nelson wrote a series of checks aggregating
approximately $4.9 million to himself and to, or for the beneÑt of, a company owned and controlled by him.
During this time, Nelson had check writing authority on the Company's principal funding account, and also
had the ability to intercept bank statement information sent to the Company. When Nelson intercepted that
information, he removed the cancelled checks reÖecting the embezzled funds from the bank statements and
then provided false information to other Company employees regarding those checks. Company employees
used the false information Nelson provided in recording the transactions.
In 1999, Nelson gained access to a form authorizing his salary increase and improperly added a provision
to it that created an additional expense allowance beneÑt of $2,000 per month, along with a provision making
the salary increase and unauthorized expense allowance retroactive for several months. Nelson added these
provisions himself and then forged the initials of the Company's Chief Executive OÇcer on the form as
authorization for these non-approved payments.
Beginning in December 2000 and continuing until October 2005, Nelson caused the wiring of Company
funds aggregating approximately $70.2 million to, or for the beneÑt of, entities owned and controlled by him.
Nelson was originally able to initiate these wire transfers by requesting the wire transfers himself in telephone
calls to one of the Company's banks. After changes to the Company's internal controls and procedures in
2004, Nelson initiated the wire transfers through instructions to one of his subordinates and by the creation of
fraudulent invoices containing forged senior management approvals.
In connection with an acquisition by the Company in early 2004, Nelson also used a wire transfer to
fraudulently divert funds from the Company. At the time of the acquisition, Nelson initiated a wire transfer for
approximately $2.1 million by sending an email to one of his subordinates in which he falsely represented that
40
the wired funds were to be used to pay oÅ the seller's obligation for an aircraft maintenance agreement relating
to the acquired business. In reality, Nelson used the funds to purchase an airplane for his personal use.
Finally, in October 2004, Nelson diverted Company funds of approximately $1.6 million to Ñnance an
investment in a company. Nelson accomplished the fraudulent diversion of Company funds by improperly
directing the bank to fund Nelson's personal investment.
After Nelson resigned from the Company in November 2005, the Company became aware that Nelson
had fraudulently diverted Company funds. As a result, the Audit Committee of the Board of Directors
commenced an investigation into Nelson's activities. The Audit Committee retained independent counsel and
independent forensic accountants to assist with the investigation.
The investigation conÑrmed the above facts and revealed that Nelson exploited the reliance placed on
him to create an environment at the Company which discouraged routine communication concerning Ñnancial
and business information within the organization between senior management (other than Nelson) and those
employees engaged in the Company's Ñnancial reporting and accounting functions (other than Nelson).
Nelson also discouraged communication between employees involved in Ñnancial reporting and accounting
functions and those involved in operational activities. The control environment at the Company resulted in
Company employees placing trust in Nelson and placed Nelson at the center of information Öows about
Ñnancial reporting and accounting matters.
The control environment allowed Nelson to override certain of the Company's internal controls and
procedures, and contributed to the failure of Company employees charged with certain Ñnancial and
accounting duties to exercise appropriate judgment, skepticism and objectivity, such that prevention or
detection of the override of established policies, procedures, controls and Nelson's inappropriate transactions
did not occur while Nelson was employed by the Company. This allowed Nelson to make unauthorized
payments for assets that were not, in fact, ordered by or delivered to the Company, and for services that were
not actually provided to the Company and to conceal the fraudulent transactions within the Company's
accounting and Ñnancial records and reports.
On December 22, 2005, the Company announced that the Audit Committee of the Board of Directors
had concluded that it was necessary to restate its previously reported consolidated Ñnancial statements for the
years ended December 31, 2004, 2003 and 2002. The Company also restated its previously reported
consolidated Ñnancial statements for the Ñrst three quarters of 2005 and all quarters in 2004 and 2003. The
Company Ñled an Annual Report on Form 10-K/A on March 17, 2006, and Quarterly Reports on Form 10-
Q/A on March 27, 2006 that included these restated consolidated Ñnancial statements. Restatement
adjustments are further described in Note 2 of the Notes to the Consolidated Financial Statements.
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive
OÇcer (CEO) and current Chief Financial OÇcer (CFO), we conducted an evaluation of the eÅectiveness of
our disclosure controls and procedures, as such term is deÑned in Rules 13a-15(e) and 15d-15(e)
promulgated under the Securities and Exchange Act of 1934, as amended (the Exchange Act), as of the end
of the period covered by this Annual Report on Form 10-K. Disclosure controls and procedures are designed
to ensure that the information required to be disclosed by us in the reports we Ñle or submit under the
Exchange Act is recorded, processed, summarized, and reported on a timely basis and that such information is
accumulated and reported to management, including our CEO and CFO, as appropriate, to allow timely
decisions regarding required disclosures.
At the time of the Ñling of our Annual Report on Form 10-K for the year ended December 31, 2004, our
CEO and former CFO concluded that our disclosure controls and procedures were eÅective as of Decem-
ber 31, 2004. Subsequent to that evaluation, our CEO and current CFO concluded that our disclosure controls
and procedures were not eÅective at a reasonable level of assurance, as of December 31, 2004, because of the
material weaknesses discussed in the Annual Report on Form 10-K/A Ñled March 17, 2006. As described
below under ""Management's Report on Internal Control Over Financial Reporting,'' the Company continues
41
to report material weaknesses in internal control over Ñnancial reporting as of December 31, 2005. The
Company's CEO and current CFO have concluded that, as of the end of the period covered by this Annual
Report on Form 10-K, the Company's disclosure controls and procedures were not eÅective at a reasonable
level of assurance. Based upon the substantial work performed during the restatement process, management
has concluded that the Company's consolidated Ñnancial statements for the periods covered by and included
in this Annual Report on Form 10-K are fairly stated in all material respects.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over Ñnancial
reporting as such term is deÑned in Exchange Act Rule 13a-15(f). Our management, including our CEO and
current CFO, conducted an evaluation of the eÅectiveness of our internal control over Ñnancial reporting as of
December 31, 2005 using the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission in Internal Control-Integrated Framework (COSO framework). Because of its
inherent limitations, internal control over Ñnancial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of eÅectiveness 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 policies or procedures may
deteriorate.
A material weakness is a control deÑciency, or combination of control deÑciencies, that results in more
than a remote likelihood that a material misstatement of the annual or interim Ñnancial statements will not be
prevented or detected.
Our current management identiÑed the following material weaknesses in our internal control over
Ñnancial reporting as of December 31, 2005:
1. Control environment. We did not maintain an eÅective control environment based on the
criteria established in the COSO framework. SpeciÑcally, the Company did not maintain a control
environment adequate to encourage the prevention or detection of the override of our controls or
intentional misconduct, including misappropriation of assets and the preparation of false management
reports, accounting records, Ñnancial statements and documents together with forged approval signatures.
This lack of an eÅective control environment allowed our former CFO to take inappropriate actions that
resulted in certain transactions not being properly reÖected in our consolidated Ñnancial statements for
the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the Ñrst
three quarters of 2005. This intentional misconduct by our former CFO included the preparation of false
accounting records and documents to deceive accounting personnel under his supervision, other members
of senior management, our Board of Directors and our independent registered public accountants.
Additionally, the lack of an eÅective control environment allowed our lines of communication among, and
our monitoring of, our operations and accounting personnel, including our former CFO, to not be eÅective
in preventing or detecting these instances of intentional misconduct. Taken as a whole, our control
environment did not adequately emphasize appropriate judgment, skepticism and objectivity, and our
former CFO intentionally exploited this environment for his personal beneÑt, speciÑcally with respect to
our controls over cash, payroll and property and equipment as follows:
a. Cash. Our former CFO manipulated the process over the initiation and approval of cash
wire transfers. This action was taken in order to accomplish the fraudulent diversion of cash from the
Company to entities owned by our former CFO for goods and services which the Company neither
requested nor received. False documentation was created by our former CFO to conceal the true
nature of these transactions from the Company and its independent registered public accountants.
b. Payroll.
In 1999, our former CFO intentionally altered his payroll records to indicate that
appropriate authorization had been given for a retroactive increase in his compensation and related
beneÑts when in fact no such authorization had been provided. This false documentation was created
by our former CFO to provide for an unauthorized increase to his compensation and to conceal the
unauthorized compensation increase from the Company and its independent registered public
accountants.
42
c. Property and Equipment. Our former CFO instructed certain former employees, who
worked under his supervision, to alter management reports related to property and equipment
expenditures. Additionally, our former CFO created Ñctitious property and equipment approval
forms with forged signatures. These actions had the eÅect of concealing his inappropriate and
fraudulent diversion of cash. The activities by our former CFO deceived the Company and its
independent registered public accountants as to the true nature of the Company's cash transfers and
property and equipment expenditures.
This control environment material weakness contributed to the embezzlement occurring, which in turn
resulted in the restatement of our consolidated Ñnancial statements for the years ended December 31, 2004,
2003 and 2002, each of the quarters of 2004 and 2003, and the Ñrst three quarters of 2005. Additionally, this
control environment material weakness could result in misstatements of any of our Ñnancial statement
accounts that would result in a material misstatement to the annual or interim consolidated Ñnancial
statements that would not be prevented or detected. Accordingly, our management has determined that this
control deÑciency constitutes a material weakness.
The material weakness in our control environment contributed to the existence of the following additional
material weakness in controls over property and equipment as described below:
2. Controls over property and equipment. We did not maintain eÅective controls over the
completeness and accuracy of our accounting for property and equipment. SpeciÑcally, our controls were
not adequate to ensure (i) the timely and accurate depreciation of all property and equipment, (ii) the
identiÑcation and recording of all property and equipment retirements when they occurred, and (iii) that
property and equipment transferred between our locations was accurately and completely reÖected in our
accounting records. This control deÑciency resulted in certain inaccuracies in our accounting for property
and equipment and in the restatement of our consolidated Ñnancial statements for the years ended
December 31, 2004, 2003 and 2002; each of the quarters of 2004 and 2003; and the Ñrst three quarters of
2005. Additionally, this control deÑciency could result in a misstatement of our property and equipment
and related depreciation expense accounts that would result in a material misstatement to the annual or
interim consolidated Ñnancial statements that would not be prevented or detected. Accordingly, our
management has determined that this control deÑciency constitutes a material weakness.
Our management, including our CEO and current CFO, have concluded that as a result of the material
weaknesses described above, we did not maintain eÅective internal control over Ñnancial reporting as of
December 31, 2005, based on the criteria in Internal Control-Integrated Framework issued by the COSO.
Our assessment of the eÅectiveness of our internal control over Ñnancial reporting as of December 31,
2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting Ñrm, as
stated in their report which begins on page F-2 of this Annual Report on Form 10-K.
Changes in Internal Control Over Financial Reporting
Management is committed to remediating each of the material weaknesses identiÑed above by
implementing changes to the Company's internal control over Ñnancial reporting. Management has imple-
mented, or is in the process of implementing, the following changes to the Company's internal control systems
and procedures:
We are strengthening our tracking system for property and equipment to improve the tracking of
those assets between our yards and rigs and to trigger the timely commencement of depreciation of assets
placed in service.
We are implementing procedures and processes to reinforce with our employees their responsibilities
to exercise independence and judgment and to comply with the Company's compliance programs,
including:
‚ formal certiÑcations of information contained in SEC Ñlings relating to their areas of
responsibility;
43
‚ annual written questionnaires from senior employees and accounting staÅ with respect to
awareness as to questionable business practices;
‚ improved education and training programs for all employees covering ethics, compliance, Ñnancial
reporting and good business practices;
‚ additional guidelines with respect to senior management's responsibilities for SEC Ñlings, Ñnancial
reports, budgets and maintenance of controls over assets and expenditures; and
‚ annual reporting to the Audit Committee with respect to these processes and procedures.
In addition, we will initiate a search for an in-house counsel whose responsibilities will include an
active role in corporate compliance and governance.
We have initiated structural changes and processes and procedures to increase communications
between the Ñnancial reporting and accounting functions and operations and between the Ñnancial
reporting and accounting functions and senior management.
Additionally, management is committed to continued improvements in controls. In this regard, we are
revising our internal audit reporting structure to further enhance its direct reporting to the audit committee
and its program of monitoring controls.
During the fourth quarter of 2005, we changed our wire transfer approval policies to require additional
and more secure authorizations for wires to ensure that all wire transfers are to approved vendors, and to
ensure that all such transactions are reÖected in the Company's accounts payable system and have appropriate
supporting documentation. We also revised our property and equipment expenditure requirements to provide
for improved controls over the authorization of Ñxed asset acquisitions. We have evaluated the design of these
new procedures, placed them in operation for a suÇcient period of time, and subjected them to appropriate
tests in order to conclude that they are operating eÅectively. These changes remediated the material weakness
in controls over cash that was reported in Management's Report on Internal Control Over Financial Reporting
included in the Company's Annual Report on Form 10-K/A for the year ended December 31, 2004
(""Management's 2004 Report''). In addition, these changes remediated the control failure over the
authorization of property and equipment acquisitions as reported in Management's 2004 Report.
Other than the changes described above, there have been no other changes in our internal control over
Ñnancial reporting during the most recently completed Ñscal quarter that have materially aÅected, or are
reasonably likely to materially aÅect, our internal control over Ñnancial reporting. The remaining remediation
activities noted above were initiated in the fourth quarter of 2005 and the remaining controls will be
implemented in 2006.
Item 9B. Other Information
None.
44
PART III
The information required by Part III is omitted from this Report because we will Ñle a deÑnitive proxy
statement pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the
end of the Ñscal year covered by this Report and certain information included therein is incorporated herein by
reference.
Item 10. Directors and Executive OÇcers of the Registrant.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
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 BeneÑcial 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.
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.
45
PART IV
Item 15. Exhibits and Financial Statement Schedule.
(a)(1) Financial Statements
See Index to Consolidated Financial Statements on page F-1 of this Report.
(a)(2) Financial Statement Schedule
Schedule II Ì Valuation and qualifying accounts is Ñled herewith on page S-1.
All other Ñnancial statement schedules have been omitted because they are not applicable or the
information required therein is included elsewhere in the Ñnancial statements or notes thereto.
(a)(3) Exhibits
The following exhibits are Ñled herewith or incorporated by reference herein.
3.1
Restated CertiÑcate of Incorporation, as amended (Ñled August 9, 2004 as Exhibit 3.1 to the
Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and
incorporated herein by reference).
3.2 Amendment to Restated CertiÑcate of Incorporation, as amended (Ñled August 9, 2004 as Exhibit 3.2
to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and
incorporated herein by reference).
3.3 Amended and Restated Bylaws (Ñled March 19, 2002 as Exhibit 3.2 to the Company's Annual Report
on Form 10-K for the Ñscal year ended December 31, 2001 and incorporated herein by reference).
Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock
Transfer & Trust Company (Ñled January 14, 1997 as Exhibit 2 to the Company's Registration
Statement on Form 8-A and incorporated herein by reference).
4.1
4.3
4.4
4.2 Amendment to Rights Agreement dated as of October 23, 2001 (Ñled 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 CertiÑcate 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 by
REMY Capital Partners III, L.P.(Ñled March 19, 2002 as Exhibit 4.3 to the Company's Annual
Report on Form 10-K for the Ñscal year ended December 31, 2001 and incorporated herein by
reference).
For additional material contracts, see Exhibits 4.1, 4.2 and 4.4.
Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as amended (Ñled March 13, 1998 as
Exhibit 10.1 to the Company's Registration Statement on Form S-8 (File No. 333-47917) and
incorporated herein by reference).*
Patterson-UTI Energy, Inc. Non-Employee Directors' Stock Option Plan, as amended (Ñled Novem-
ber 4, 1997 as Exhibit 10.1 to the Company's Registration Statement on Form S-8 (File
No. 333-39471) and incorporated herein by reference).*
10.1
10.2
10.3
10.4 Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (Ñled Novem-
ber 27, 2002 as Exhibit 4.4 to Post EÅective Amendment No. 1 to the Company's Registration
Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (Ñled July 28,
2003 as Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 2003 and incorporated herein by reference).*
10.5
10.6 Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive
Plan (Ñled 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).*
46
10.7 Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(Ñled
July 28, 2003 as Exhibit 4.8 to the Company's Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 2003 and incorporated herein by reference).*
10.8 Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (Ñled July 25,
2001 as Exhibit 4.4 to Post-EÅective Amendment No. 1 to the Company's Registration Statement on
Form S-8 (File No. 333-60466) and incorporated herein by reference).*
1997 Stock Option Plan of DSI Industries, Inc. (Ñled July 25, 2001 as Exhibit 4.4 to Post-EÅective
Amendment No. 1 to the Company's Registration Statement on Form S-8 (File No. 333-60470) and
incorporated herein by reference).*
10.9
10.10 Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive OÇcer
Restricted Stock Award Agreement, Form of Executive OÇcer Stock Option Agreement, Form of
Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director
Stock Option Agreement (Ñled June 15, 2005 as Exhibit 10.1 to the Company's Current Report on
Form 8-K, and incorporated herein by reference).*
10.11 Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and
Mark S. Siegel (Ñled August 9, 2004 as Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
10.12 Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and
Cloyce A. Talbott (Ñled August 9, 2004 as Exhibit 10.2 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
10.13 Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and A.
Glenn Patterson (Ñled August 9, 2004 as Exhibit 10.3 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
10.14 Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and
Kenneth N. Berns (Ñled August 9, 2004 as Exhibit 10.4 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
10.15 Restricted Stock Award Agreement dated April 28, 2004 between Patterson-UTI Energy, Inc. and
John E. Vollmer III (Ñled August 9, 2004 as Exhibit 10.6 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
10.16 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and
between Patterson-UTI Energy, Inc. and Mark S. Siegel (Ñled on February 4, 2004 as Exhibit 10.2 to
the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated
herein by reference).*
10.17 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and
between Patterson-UTI Energy, Inc. and A. Glenn Patterson (Ñled on February 4, 2004 as
Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003
and incorporated herein by reference).*
10.18 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and
between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (Ñled on February 4, 2004 as Exhibit 10.4
to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and
incorporated herein by reference).*
10.19 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and
between Patterson-UTI Energy, Inc. and Kenneth N. Berns (Ñled on February 4, 2004 as Exhibit 10.5
to the Company's Annual Report on Form 10-K for the year ended December 31, 2003 and
incorporated herein by reference).*
10.20 Patterson-UTI Energy, Inc. Change in Control Agreement, eÅective as of January 29, 2004, by and
between Patterson-UTI Energy, Inc. and John E. Vollmer III (Ñled on February 4, 2004 as
Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003
and incorporated herein by reference).*
10.21 Form of Letter Agreement regarding termination, eÅective 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
(Ñled 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).*
47
10.22 Form of IndemniÑcation Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S.
Siegel, Cloyce A. Talbott, A. Glenn Patterson, Kenneth N. Berns, Robert C. Gist, Curtis W. HuÅ,
Terry H. Hunt, Kenneth R. Peak, Nadine C. Smith and John E. Vollmer III (Ñled 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).*
10.23 Credit Agreement dated as of December 17, 2004 among Patterson-UTI Energy, Inc., as the
Borrower, Bank of America, N.A., as administrative agent, L/C Issuer and a Lender and the other
lenders and agents party thereto (Ñled on December 23, 2004 as Exhibit 10.1 to the Company's
Current Report on Form 8-K and incorporated herein by reference).
10.24 Summary Description of 2005 Bonus Compensation Program (Ñled on April 29, 2005 in the
Company's Current Report on Form 8-K and incorporated herein by reference).*
14.1
10.25 Summary Description of Director Compensation (Ñled on February 25, 2005 as Exhibit 10.27 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. Code of Business Conduct and Ethics for Senior Financial Executives
(Ñled on February 4, 2004 as Exhibit 14.1 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2003 and incorporated herein by reference).
Subsidiaries of the Registrant.
Consent of Independent Registered Public Accounting Firm.
CertiÑcation of Chief Executive OÇcer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities
Exchange Act of 1934, as amended.
CertiÑcation of Chief Financial OÇcer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities
Exchange Act of 1934, as amended.
CertiÑcation of Chief Executive OÇcer and Chief Financial OÇcer pursuant to 18 USC Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
21.1
23.1
31.1
31.2
32.1
* Management Contract or Compensatory Plan identiÑed as required by Item 15(a)(3) of Form 10-K.
48
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting Firm ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-2
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2005 and 2004ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-5
Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003 ÏÏÏÏÏÏÏ F-6
Consolidated Statements of Changes In Stockholders' Equity for the years ended December 31,
2005, 2004 and 2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-7
Consolidated Statements of Changes In Cash Flows for the years ended December 31, 2005, 2004
and 2003ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-8
Notes to Consolidated Financial Statements ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ F-9
Financial Statement Schedule ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ S-1
F-1
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Patterson-UTI Energy, Inc.
We have completed integrated audits of Patterson-UTI Energy, Inc.'s 2005 and 2004 consolidated
Ñnancial statements and of its internal control over Ñnancial reporting as of December 31, 2005, and an audit
of its 2003 consolidated Ñnancial statements in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated Ñnancial statements and Ñnancial statement schedule
In our opinion, the consolidated Ñnancial statements listed in the accompanying index present fairly, in all
material respects, the Ñnancial position of Patterson-UTI Energy, Inc. and its subsidiaries at December 31,
2005 and 2004, and the results of their operations and their cash Öows for each of the three years in the period
ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the Ñnancial 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 Ñnancial statements. These Ñnancial statements and Ñnancial
statement schedule are the responsibility of the Company's management. Our responsibility is to express an
opinion on these Ñnancial statements and Ñnancial statement schedule based on our audits. We conducted our
audits of these statements in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the Ñnancial statements are free of material misstatement. An audit of Ñnancial
statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the
Ñnancial statements, assessing the accounting principles used and signiÑcant estimates made by management,
and evaluating the overall Ñnancial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
As discussed in Note 2 to the consolidated Ñnancial statements, the Company restated its 2004 and 2003
consolidated Ñnancial statements.
Internal control over Ñnancial reporting
Also, we have audited management's assessment, included in Management's Report on Internal Control
Over Financial Reporting appearing under Item 9A, that Patterson-UTI Energy, Inc. did not maintain
eÅective internal control over Ñnancial reporting as of December 31, 2005, because the Company did not
maintain (1) an eÅective control environment and (2) eÅective controls over property and equipment, based
on criteria established in Internal Control Ì Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's management is responsible for
maintaining eÅective internal control over Ñnancial reporting and for its assessment of the eÅectiveness of
internal control over Ñnancial reporting. Our responsibility is to express opinions on management's assessment
and on the eÅectiveness of the Company's internal control over Ñnancial reporting based on our audit.
We conducted our audit of internal control over Ñnancial reporting in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether eÅective internal control over Ñnancial
reporting was maintained in all material respects. An audit of internal control over Ñnancial reporting includes
obtaining an understanding of internal control over Ñnancial reporting, evaluating management's assessment,
testing and evaluating the design and operating eÅectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinions.
A company's internal control over Ñnancial reporting is a process designed to provide reasonable
assurance regarding the reliability of Ñnancial reporting and the preparation of Ñnancial statements for external
purposes in accordance with generally accepted accounting principles. A company's internal control over
F-2
Ñnancial reporting includes those policies and procedures that (i) pertain to the maintenance of records that,
in reasonable detail, accurately and fairly reÖect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of Ñnancial
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 eÅect on the Ñnancial
statements.
Because of its inherent limitations, internal control over Ñnancial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of eÅectiveness 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.
A material weakness is a control deÑciency, or combination of control deÑciencies, that results in more
than a remote likelihood that a material misstatement of the annual or interim Ñnancial statements will not be
prevented or detected. The following material weaknesses have been identiÑed and included in management's
assessment as of December 31, 2005.
1. Control environment. The Company did not maintain an eÅective control environment based on
the criteria established in the COSO framework. SpeciÑcally, the Company did not maintain a control
environment adequate to encourage the prevention or detection of the override of controls or intentional
misconduct, including misappropriation of assets and the preparation of false management reports,
accounting records, Ñnancial statements and documents together with forged approval signatures. This
lack of an eÅective control environment allowed the Company's former CFO to take inappropriate
actions that resulted in certain transactions not being properly reÖected in the Company's consolidated
Ñnancial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004
and 2003, and the Ñrst three quarters of 2005. This intentional misconduct by the Company's former
CFO included the preparation of false accounting records and documents to deceive accounting personnel
under his supervision, other members of senior management, the Board of Directors and its independent
registered public accountants. Additionally, the lack of an eÅective control environment allowed the
Company's lines of communication among, and their monitoring of, their operations and accounting
personnel, including their former CFO, to not be eÅective in preventing or detecting these instances of
intentional misconduct. Taken as a whole, the Company's control environment did not adequately
emphasize appropriate judgment, skepticism and objectivity, and their former CFO intentionally
exploited this environment for his personal beneÑt, speciÑcally with respect to the Company's controls
over cash, payroll and property and equipment as follows:
a. Cash. The Company's former CFO manipulated the process over the initiation and
approval of cash wire transfers. This action was taken in order to accomplish the fraudulent diversion
of cash from the Company to entities owned by their former CFO for goods and services which the
Company neither requested nor received. False documentation was created by the Company's
former CFO to conceal the true nature of these transactions from the Company and its independent
registered public accountants.
b. Payroll.
In 1999, the Company's former CFO intentionally altered his payroll records to
indicate that appropriate authorization had been given for a retroactive increase in his compensation
and related beneÑts when in fact no such authorization had been provided. This false documentation
was created by the Company's former CFO to provide for an unauthorized increase to his
compensation and to conceal the unauthorized compensation increase from the Company and its
independent registered public accountants.
c. Property and Equipment. The Company's former CFO instructed certain former employ-
ees, who worked under his supervision, to alter management reports related to property and
equipment expenditures. Additionally, the Company's former CFO created Ñctitious property and
equipment approval forms with forged signatures. These actions had the eÅect of concealing his
F-3
inappropriate and fraudulent diversion of cash. The activities by the Company's former CFO
deceived the Company and its independent registered public accountants as to the true nature of the
Company's cash transfers and property and equipment expenditures.
The Company's material weakness in its control environment contributed to the existence of the material
weakness in controls over property and equipment as described below:
2. Controls over property and equipment. The Company did not maintain eÅective controls over
the completeness and accuracy of their accounting for property and equipment. SpeciÑcally, the
Company's controls were not adequate to ensure (i) the timely and accurate depreciation of all property
and equipment, (ii) the identiÑcation and recording of all property and equipment retirements when they
occurred, and (iii) that property and equipment transferred between Company locations was accurately
and completely reÖected in their accounting records. This control deÑciency resulted in certain
inaccuracies in the Company's accounting for property and equipment.
The control deÑciencies described above resulted in the restatement of the Company's consolidated
Ñnancial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and
2003, and the Ñrst three quarters of 2005. Additionally, each of the control deÑciencies described above could
result in a misstatement in the aforementioned accounts or disclosures that would result in a material
misstatement in the Company's annual or interim consolidated Ñnancial statement that would not be
prevented or detected. Accordingly, the Company's management has determined that each of these control
deÑciencies constitute material weaknesses.
These material weaknesses were considered in determining the nature, timing, and extent of audit tests
applied in our audit of the 2005 consolidated Ñnancial statements, and our opinion regarding the eÅectiveness
of the Company's internal control over Ñnancial reporting does not aÅect our opinion on those consolidated
Ñnancial statements.
In our opinion, management's assessment that Patterson-UTI Energy, Inc. did not maintain eÅective
internal control over Ñnancial reporting as of December 31, 2005, is fairly stated, in all material respects, based
on criteria established in Internal Control Ì Integrated Framework issued by the COSO. Also, in our opinion,
because of the eÅects of the material weaknesses described above on the achievement of the objectives of the
control criteria, Patterson-UTI Energy, Inc. has not maintained eÅective internal control over Ñnancial
reporting as of December 31, 2005, based on criteria established in Internal Control Ì Integrated Framework
issued by the COSO.
PricewaterhouseCoopers LLP
Houston, Texas
March 29, 2006
F-4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
Restated
(See Note 2)
2004
2005
(In thousands,
except share data)
Current assets:
ASSETS
Cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accounts receivable, net of allowance for doubtful accounts of $2,199 and
$1,909 at December 31, 2005 and 2004, respectively ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Inventory ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred tax assets, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Property and equipment, at cost, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total assetsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 136,398
$ 112,371
422,002
27,907
26,382
25,168
637,857
1,053,845
99,056
5,023
$1,795,781
214,097
17,738
15,991
26,836
387,033
765,019
99,056
5,677
$1,256,785
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
TradeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accrued revenue distributions ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accrued Federal and state income taxes payable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accrued expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total current liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred tax liabilities, net ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
OtherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Commitments and contingencies ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Stockholders' equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued
Common stock, par value $.01; authorized 300,000,000 shares with
175,909,274 and 171,625,841 issued and 172,441,178 and 168,512,745
outstanding at December 31, 2005 and 2004, respectively ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Additional paid-in capital ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred compensation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Retained earnings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accumulated other comprehensive income, net of tax ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Treasury stock, at cost, 3,468,096 shares and 3,113,096 (aÅected by a two-
$ 113,226
13,379
5,294
11,034
112,476
255,409
169,188
4,173
428,770
Ì
$
54,553
11,297
2,309
4,231
79,163
151,553
140,475
3,256
295,284
Ì
Ì
Ì
1,759
672,151
(9,287)
719,113
8,565
1,716
597,280
(5,420)
373,712
7,350
for-one stock split) shares at December 31, 2005 and 2004, respectivelyÏÏÏ
Total stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total liabilities and stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(25,290)
1,367,011
$1,795,781
(13,137)
961,501
$1,256,785
The accompanying notes are an integral part of these consolidated Ñnancial statements.
F-5
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Operating revenues:
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating costs and expenses:
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumping ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrative ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Bad debt expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Embezzled funds and related expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other (including gain or loss on sale of assets) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other income (expense):
Interest income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Years Ended December 31,
Restated (See Note 2)
2005
2003
2004
(In thousands, except per share data)
$1,485,684
93,144
122,011
39,616
1,740,455
$ 809,691
66,654
90,557
33,867
1,000,769
$639,694
46,083
69,230
21,163
776,170
776,313
54,956
98,530
9,566
156,393
39,110
1,231
20,043
3,017
1,159,159
581,296
3,551
(516)
428
3,463
556,869
37,561
76,503
7,978
122,800
31,983
897
19,122
(1,411)
852,302
148,467
1,140
(695)
235
680
475,224
26,184
61,424
4,808
100,834
27,685
259
17,849
(4,379)
709,888
66,282
1,116
(292)
1,870
2,694
Income before income taxes and cumulative eÅect of change in
accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
584,759
149,147
68,976
Income tax expense (beneÑt):
Current ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
DeferredÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income before cumulative eÅect of change in accounting principle ÏÏÏÏÏÏ
Cumulative eÅect of change in accounting principle, net of related
income tax beneÑt of approximately $287 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
194,918
17,101
212,019
372,740
Ì
$ 372,740
Net income per common share:
Basic:
Income before cumulative eÅect of change in accounting principle ÏÏ
Cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted:
Income before cumulative eÅect of change in accounting principle ÏÏ
Cumulative eÅect of change in accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Weighted average number of common shares outstanding:
BasicÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
$
$
$
$
$
2.19
Ì $
Ì $
2.19
2.15
$
$
0.57
0.56
$
$
Ì $
Ì $
Ì
0.27
0.27
Ì
2.15
$
0.56
$
0.26
170,426
173,767
166,258
169,211
161,272
164,572
39,952
14,849
54,801
94,346
Ì
94,346
15,324
9,996
25,320
43,656
(469)
$ 43,187
0.57
$
0.27
$
$
The accompanying notes are an integral part of these consolidated Ñnancial statements.
F-6
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Common Stock
Number
of Shares Amount
Additional
Paid-In
Capital
Deferred
Compensation
Retained
Earnings
Accumulated
Other
Comprehensive
Income
(Loss)
Treasury
Stock
Total
81,577
$ 816
$489,201
$ Ì $261,208
$(1,839)
$(11,655) $ 737,731
Ì
Ì
Ì
Ì
Ì
Ì
81,577
816
489,201
906
Ì
Ì
Ì
9
Ì
Ì
Ì
10,277
6,540
Ì
Ì
82,483
825
506,018
Ì
(12,499)
Ì
Ì
(12,499)
(1,659)
675
Ì
(984)
247,050
(1,164)
(11,655)
724,248
Ì
Ì
Ì
43,187
Ì
Ì
5,553
Ì
Ì
Ì
Ì
Ì
10,286
6,540
5,553
43,187
290,237
4,389
(11,655)
789,814
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
(6,642)
1,388
189
Ì
2,580
Ì
Ì
Ì
Ì
14
2
Ì
25
Ì
Ì
Ì
Ì
84,986
Ì
850
Ì
49,462
6,640
Ì
1,222
24,494
10,666
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
(10,021)
(850)
94,346
Ì
Ì
Ì
Ì
Ì
2,961
Ì
Ì
Ì
Ì
171,626
305
1,716
3
597,280
8,040
(5,420)
(8,043)
373,712
Ì
7,350
Ì
Ì
(65)
4,043
Ì
Ì
Ì
Ì
Ì
Ì
Ì
40
Ì
Ì
Ì
Ì
Ì
Ì
(1,351)
43,434
24,748
Ì
Ì
Ì
Ì
2,825
1,351
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
(27,339)
372,740
Ì
Ì
Ì
Ì
1,215
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
Ì
(1,482)
Ì
Ì
Ì
(13,137)
Ì
Ì
Ì
Ì
Ì
Ì
(12,153)
Ì
Ì
49,476
Ì
1,222
24,519
10,666
2,961
(1,482)
(10,021)
Ì
94,346
961,501
Ì
2,825
Ì
43,474
24,748
1,215
(12,153)
(27,339)
372,740
December 31, 2002, as
previously reported ÏÏÏÏÏÏÏÏ
Adjustment for eÅects of
embezzlement (net of
applicable income tax
beneÑt of $7,622)(See
Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other adjustments (net of
applicable income tax
beneÑt of $691) (See
Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
December 31, 2002, as restated
(See Note 2) ÏÏÏÏÏÏÏÏÏÏÏÏÏ
Exercise of stock options and
warrants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Tax beneÑt related to
exercise of stock options ÏÏ
Foreign currency translation
adjustment, (net of tax of
$3,220) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net income, as restated (See
Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
December 31, 2003, as restated
(See Note 2) ÏÏÏÏÏÏÏÏÏÏÏÏÏ
Issuance of common stock
for acquisition ÏÏÏÏÏÏÏÏÏÏ
Issuance of restricted stock
Amortization of deferred
compensation expense ÏÏÏÏ
Exercise of stock options and
warrants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Tax beneÑt related to
exercise of stock options ÏÏ
Foreign currency translation
adjustment, (net of tax of
$1,716) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Purchase of treasury stock ÏÏ
Payment of cash dividend
(see Note 12) ÏÏÏÏÏÏÏÏÏÏ
EÅect of two-for-one stock
split (see Note 12) ÏÏÏÏÏÏ
Net income, as restated (See
Note 2)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
December 31, 2004, as restated
(See Note 2) ÏÏÏÏÏÏÏÏÏÏÏÏÏ
Issuance of restricted stock
Amortization of deferred
compensation expense ÏÏÏÏ
Forfeitures of restricted
shares ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Exercise of stock options ÏÏÏ
Tax beneÑt related to
exercise of stock options ÏÏ
Foreign currency translation
adjustment, (net of tax of
$705) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Purchase of treasury stock ÏÏ
Payment of cash dividend
(see Note 12) ÏÏÏÏÏÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
December 31, 2005 ÏÏÏÏÏÏÏÏÏÏ
175,909
$1,759
$672,151
$(9,287)
$719,113
$ 8,565
$(25,290) $1,367,011
The accompanying notes are an integral part of these consolidated Ñnancial statements.
F-7
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
Cash Öows from operating activities:
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and impairmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Provision for bad debtsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Tax beneÑt related to exercise of stock optionsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Amortization of deferred compensation expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Gain on sale of assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cumulative eÅect of change in accounting principle, net of tax ÏÏ
Changes in operating assets and liabilities, net of business
acquired:
Accounts receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Federal income taxes receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Inventory and other current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accounts payable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accrued expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net cash provided by operating activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cash Öows from investing activities:
Acquisitions, net of cash acquiredÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Purchases of property and equipmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Proceeds from sales of property and equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Change in other assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net cash used in investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cash Öows from Ñnancing activities:
Years Ended December 31,
2005
Restated (See Note 2)
2004
2003
(In thousands)
$ 372,740
$
94,346
$
43,187
156,393
1,231
17,101
24,748
2,825
(1,253)
Ì
(208,248)
7,068
(9,402)
60,860
32,514
3,902
460,479
(73,577)
(380,094)
12,674
1,766
(439,231)
122,800
897
14,849
10,666
1,222
(1,411)
Ì
(50,682)
15,734
(13,556)
12,861
1,555
(6,090)
203,191
100,834
259
9,996
6,540
Ì
(1,927)
(469)
(55,791)
11,155
(8,984)
12,322
22,814
5,015
144,951
(30,387)
(174,589)
3,303
(1,766)
(203,439)
(40,832)
(98,801)
4,548
(1,693)
(136,778)
Purchase of treasury stock ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Dividends paidÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Line of credit issuance costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Proceeds from exercise of stock options and warrants ÏÏÏÏÏÏÏÏÏÏ
Net cash provided by Ñnancing activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
EÅect of foreign exchange rate changes on cashÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net increase in cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cash and cash equivalents at beginning of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Cash and cash equivalents at end of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(12,153)
(27,339)
Ì
43,474
3,982
(1,203)
24,027
112,371
$ 136,398
(1,482)
(10,021)
(780)
24,519
12,236
(100)
Ì
Ì
Ì
10,286
10,286
(130)
11,888
100,483
$ 112,371
18,329
82,154
$ 100,483
Supplemental disclosure of cash Öow information:
Net cash received (paid) during the year for:
Interest expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
(418)
(156,709)
$
(245)
(12,500)
$
(292)
2,730
The accompanying notes are an integral part of these consolidated Ñnancial statements.
F-8
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Summary of SigniÑcant Accounting Policies
A description of the business and basis of presentation follows:
Description of business Ì Patterson-UTI Energy, Inc., together with its wholly-owned subsidiaries,
(collectively referred to herein as ""Patterson-UTI'' or the ""Company'') is a leading provider of onshore
contract drilling services to major and independent oil and natural gas operators in Texas, New Mexico,
Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and
Western Canada. As of December 31, 2005, the Company owned 403 drilling rigs. The Company provides
pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. The Company
provides drilling Öuids, completion Öuids and related services to oil and natural gas operators oÅshore in the
Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of
Louisiana. The Company is also engaged in the development, exploration, acquisition and production of oil
and natural gas. The Company's oil and natural gas business operates primarily in producing regions of West
and South Texas, Southeastern New Mexico, Utah and Mississippi.
Embezzlement and Restatement Ì The Company's former Chief Financial OÇcer (""CFO'') perpetrated
an embezzlement over a period of more than Ñve years. The accompanying 2004 and 2003 consolidated
Ñnancial statements have been restated to reÖect the eÅects of losses incurred as a result of the embezzlement
in the periods of occurrence. Payments related to the embezzlement previously capitalized as property and
equipment and goodwill acquired, and the related depreciation and other amounts expensed have been
reversed from the Company's accounting records. Embezzled payments have been recognized as expense in
the periods they were embezzled. The cumulative eÅects of the embezzlement prior to 2002, have been
recognized as a reduction of retained earnings. The accompanying consolidated Ñnancial statements have also
been restated for the eÅects of the correction of other errors that are immaterial both individually and in the
aggregate (See Note 2).
Basis of presentation Ì As a result of the Company increasing its ownership of TMBR/Sharp Drilling,
Inc. (""TMBR'') from 19.5% to 100% in 2004, the consolidated Ñnancial statements of Patterson-UTI Energy,
Inc. and its wholly-owned subsidiaries have been restated in accordance with the requirements of accounting
for business combinations accounted for as a purchase, to provide for the retroactive application of the equity
method of accounting for the Company's investment in TMBR (see Note 7).
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 their functional currency. The eÅects of exchange rate changes
are reÖected in accumulated other comprehensive income, which is a separate component of stockholders'
equity.
On April 28, 2004, the Company's Board of Directors authorized a two-for-one stock split in the form of a
stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. At June 30,
2004, an adjustment was made to reclassify an amount from retained earnings to common stock to account for
the par value of the common stock issued as a stock dividend. This adjustment had no overall eÅect on equity.
Historical earnings per share amounts included in the Statements of Income and elsewhere in these Ñnancial
statements have been restated as if the two-for-one stock split had occurred on January 1, 2003.
A summary of the signiÑcant accounting policies follows:
Principles of consolidation Ì The consolidated Ñnancial statements include the accounts of Patterson-
UTI and its wholly-owned subsidiaries. All signiÑcant intercompany accounts and transactions have been
eliminated. The Company has no controlling Ñnancial interests in any entity which would require
consolidation.
F-9
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
Management estimates Ì The preparation of Ñnancial statements in conformity with accounting princi-
ples generally accepted in the United States of America requires management to make estimates and
assumptions that aÅect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the Ñnancial statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could diÅer from such estimates.
Revenue recognition Ì 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, as described below. The Company follows the percentage-of-completion method of
accounting for footage contract drilling arrangements. Under the percentage-of-completion method, manage-
ment estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the
well. Due to the nature of turnkey contract drilling arrangements and risks therein, the Company follows the
completed contract method of accounting for such arrangements. Under this method, all drilling revenues and
expenses related to a well in progress are deferred and recognized in the period the well is completed.
Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to
exceed estimated total revenues. The Company recognizes reimbursements received from third parties for
out-of-pocket expenses incurred as revenues and accounts for these out-of-pocket expenses as direct costs.
Accounts receivable Ì Trade accounts receivable are recorded at the invoiced amount and do not bear
interest. 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 monthly. SigniÑcant 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 Ì Inventories consist primarily of chemical products to be used in conjunction with the
Company's drilling and completion Öuids activities. The inventories are stated at the lower of cost or market,
determined by the Ñrst-in, Ñrst-out method.
Property and equipment Ì Property and equipment is carried at cost less accumulated depreciation.
Depreciation is provided on the straight-line method over the estimated useful lives. The method of
depreciation does not change when equipment becomes idle. The estimated useful lives, in years, are deÑned
below.
Useful Lives
Drilling rigs and related equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
OÇce furniture ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Buildings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Automotive equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2-15
3-10
5-20
2-7
3-7
Oil and natural gas properties Ì Oil and natural gas properties are accounted for using the successful
eÅorts method of accounting. Under the successful eÅorts 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 the related reserve classiÑcation. If the reserve classiÑcation is uncertain after one year following
the completion of drilling, the Company considers the costs of the well to be impaired and recognizes the costs
as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain
undeveloped properties are charged to expense when incurred. The capitalized costs of both developmental
F-10
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and
intangible development costs, are depreciated, depleted and amortized on the units-of-production method,
based on engineering estimates of proved oil and natural gas reserves of each respective Ñeld. The Company
reviews its proved oil and natural gas properties for impairment when an event occurs such as downward
revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by Ñeld
and undiscounted cash Öow estimates are provided by an independent petroleum engineer. If the net book
value of a Ñeld exceeds its undiscounted cash Öow estimate, impairment expense is measured and recognized
as the diÅerence between its net book value and discounted cash Öow. Unproved oil and natural gas properties
are reviewed quarterly to determine impairment. The Company's intent to drill, lease expiration and
abandonment of area are considered. Assessment of impairment is made on a lease-by-lease basis. If an
unproved property is determined to be impaired, costs related to that property are expensed.
Goodwill Ì Goodwill is considered to have an indeÑnite useful economic life and is not amortized. As
such, the Company assesses impairment of its goodwill annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its carrying value.
The following table summarizes depreciation, depletion and impairment expense for 2005, 2004 and 2003
(in millions):
Restated
(See Note 2)
2005
2004
2003
Depreciation expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Depletion expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Amortization expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Impairment of oil and natural gas properties ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$141.7
10.3
Ì
4.4
$109.4
10.1
0.1
3.2
$ 93.7
5.6
0.1
1.4
Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$156.4
$122.8
$100.8
Maintenance and repairs Ì Maintenance and repairs are charged to expense when incurred. Renewals
and betterments which extend the life or improve existing property and equipment are capitalized.
Retirements Ì Upon disposition or retirement of property and equipment, the cost and related accumu-
lated depreciation are removed and any resulting gain or loss is credited or charged to operations.
Investments in equity securities Ì Investments in equity securities are accounted for under the equity
method of accounting.
Earnings per share Ì The Company provides a dual presentation of its earnings per share; Basic
Earnings per Share (""Basic EPS'') and Diluted Earnings per Share (""Diluted EPS''). Basic EPS is computed
using the weighted average number of shares outstanding during the year. Diluted EPS includes common
stock equivalents which are dilutive to earnings per share. For the years ended December 31, 2005, 2004 and
2003, dilutive securities, consisting of certain stock options and warrants (See Note 12), included in the
calculation of Diluted EPS were 3.3 million shares, 3.0 million shares and 3.3 million shares, respectively. At
December 31, 2005, there were no potentially dilutive securities and at December 31, 2004 and 2003, there
were potentially dilutive securities of 640,000 and 1.9 million, respectively, excluded from the calculation of
Diluted EPS as their exercise prices were greater than the average market price for the respective year.
Income taxes Ì 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 diÅerences between the Ñnancial 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 diÅerences
F-11
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
are expected to be recovered or settled. The eÅect 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.
Stock based compensation Ì During June 2005, the Company's shareholders approved the Patterson-
UTI Energy, Inc. 2005 long-Term Incentive Plan (the ""2005 Plan''). In addition, the Board of Directors
adopted a resolution that no future grants would be made under any of the previously existing equity plans of
the Company. The Company accounts for activity under the 2005 Plan and previous activity of its other equity
plans using the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued
to Employees (""APB 25''), and related interpretations. During the second quarters of 2004 and 2005 and the
third quarter of 2005, the company granted restricted shares of the Company's common stock (the
""Restricted Shares'') to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term
Incentive Plan, as amended, and the 2005 Plan. As required by APB 25, the Restricted Shares were valued
based upon the market price of the Company's common stock on the date of the grant. The resulting value is
being amortized over the vesting period of the stock. For the years ended December 31, 2005 and 2004,
compensation expense of $1.8 million and $773,000, net of $327,000 and $5,000 of forfeitures and of
$1.0 million and $449,000 of taxes, respectively, was included as a reduction in net income. Other than the
restricted Shares discussed above, no additional stock-based employee compensation expense is reÖected in
net income, as all options granted under the plans discussed above had an exercise price equal to the market
value of the underlying common stock on the date of grant. The following table illustrates the eÅect on net
income and net income per share if the Company had applied the fair value recognition provisions of Financial
Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation (""SFAS 123''),
to stock-based employee compensation (in thousands, except per share amounts):
Net income, as reportedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Add: Stock-based employee compensation expense recorded,
Years Ended December 31,
Restated (See Note 2)
2005
2004
2003
$372,740
$ 94,346
$ 43,187
net of forfeitures and taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1,795
773
Ì
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax eÅects(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(11,119)
(12,304)
(10,506)
Pro forma net incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$363,416
$ 82,815
$ 32,681
Earnings per share:
Basic, as reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Basic, pro forma ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted, as reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted, pro forma ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Weighted-average fair value per share of options granted(1)
$
$
$
$
$
2.19
2.13
2.15
2.11
6.33
$
$
$
$
$
0.57
0.50
0.56
0.49
6.25
$
$
$
$
$
0.27
0.20
0.26
0.20
5.59
(1) See Note 13 for additional information regarding the computations presented here.
Statement of cash Öows Ì For purposes of reporting cash Öows, cash and cash equivalents include cash
on deposit, money market funds and investment grade municipal and commercial bonds with original
maturities of 90 days or less.
F-12
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
Recently Issued Accounting Standards Ì The Financial Accounting standards Board (""FASB'') issued
StaÅ Position FIN 47, Accounting for Conditional Asset Retirement Obligations (""FIN 47''), an interpretation
of FASB Statement No. 143, in March 2005. The statement clariÑes the term ""conditional asset retirement
obligation'' as used in FASB 143. The provisions of FIN 47, which the Company adopted on December 31,
2005, did not have a material impact on the Company's Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based
Payment (""SFAS 123(R)'') in December 2004; it replaces FASB Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), companies would have
been required to implement the standard as of the beginning of the Ñrst interim reporting period that begins
after June 15, 2005. However, in April 2005, the SEC announced the adoption of an Amendment to
Rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R) that amends the
compliance dates and allows companies to implement SFAS 123(R) beginning with the Ñrst annual reporting
period beginning on or after June 15, 2005. The Company intends to adopt SFAS 123(R) on January 1, 2006.
We currently use the intrinsic value method to value stock options, and accordingly, no compensation
expense has been recognized for stock options since we grant stock options with exercise prices equal to our
common stock market price on the date of the grant. SFAS 123(R) requires the expensing of all stock-based
compensation, including stock options and restricted shares, using the fair value method. We intend to expense
stock options using the ModiÑed Prospective Transition method as described in SFAS 123(R). This method
will require expense to be recognized for stock options over their respective remaining vesting periods. No
expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R). We are
evaluating the impact of the adoption of SFAS 123(R) on our results of operations and Ñnancial position.
Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs Ì an
amendment of ARB No. 43, Chapter 4 (""SFAS 151''). SFAS 151 is eÅective, and will be adopted, for
inventory costs incurred during Ñscal years beginning after June 15, 2005 and is to be applied prospectively.
SFAS 151 amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to require current period
recognition of abnormal amounts of idle facility expense, freight, handling costs and wasted material
(spoilage). Adoption is not expected to have a material eÅect on our Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary
Assets Ì an amendment of APB Opinion No. 29 (""SFAS 153''). FAS 153 is eÅective, and will be adopted,
for nonmonetary asset exchanges occurring in Ñscal periods beginning after June 15, 2005 and is to be applied
prospectively. SFAS 153 eliminates the exception for fair value treatment of nonmonetary exchanges of
similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do
not have commercial substance. A nonmonetary exchange has commercial substance if the future cash Öows
of the entity are expected to change signiÑcantly as a result of the exchange. Adoption is not expected to have
a material eÅect on our Ñnancial position or results of operations.
The FASB issued Statement of Financial Accounting standards No. 154, Accounting changes and Error
Corrections Ì a replacement of APB Opinion No. 20 and FASB Statement No. 3 (""SFAS 154''). SFAS 154
is eÅective, and will be adopted for accounting changes made in Ñscal years beginning after December 15,
2005 and is to be applied retrospectively. SFAS 154 requires that retroactive application of a change in
accounting principle be limited to the direct eÅects of the change. Adoption is not expected to have a material
eÅect on the Company's Ñnancial position or results of operations.
ReclassiÑcations Ì Certain reclassiÑcations have been made to the 2004 and 2003 consolidated Ñnancial
statements in order for them to conform with the 2005 presentation.
F-13
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
2. Embezzlement and Restatements
On November 3, 2005, the Company announced the resignation of its CFO, Jonathan D. Nelson
(""Nelson''). On November 10, 2005, the Company announced that, based on information received by
Company senior management on November 9, 2005, the Audit Committee of the Company's Board of
Directors began an investigation into an apparent embezzlement from the Company by Nelson.
On December 22, 2005, upon recommendation of Company management and the Audit Committee of its
Board of Directors, the Company announced that based on the results to date of its internal investigation into
the facts and circumstances surrounding the embezzlement by Nelson, the Company would restate previously
issued Ñnancial statements and amend its previously issued Annual Report on Form 10-K for the year ended
December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and
September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the
beneÑt of Nelson that had been recognized in the Company's accounting records and previously issued
Ñnancial statements as payments for assets and services that were not received by the Company. Previously
issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are
immaterial both individually and in the aggregate. These other adjustments relate primarily to previously
reported property and equipment balances that resulted from our review of our property and equipment
records and the underlying physical assets in connection with investigation of the embezzlement. The
Company has restated such Ñnancial statements, and on March 17, 2006, the Company Ñled its amended
Annual Report on Form 10-K/A and on March 27, 2006, the Company Ñled its amended Quarterly Reports
on Form 10-Q/A with the SEC.
Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating
approximately $72.3 million, to, or for the beneÑt of, entities owned and controlled by him. Nelson was
originally able to initiate these wire transfers by requesting the wire transfers himself in telephone calls to one
of the Company's banks. After changes to the Company's internal controls and procedures in 2004, Nelson
initiated the wire transfers through instructions to one of his subordinates and by the creation of fraudulent
invoices containing forged senior management approvals. This false documentation was created by our former
CFO to conceal the true nature of these transactions from the Company and its independent registered public
accountants.
Nelson also instructed certain former employees, who worked under his supervision, to alter management
reports related to property and equipment expenditures. Nelson also created Ñctitious property and equipment
approval forms with forged signatures.
The total amount embezzled was approximately $77.5 million in cash, excluding any tax eÅects,
beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):
From 1998 to December 31, 2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From January 1, 2005 to September 30, 2005(1)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total through September 30, 2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1) ÏÏÏÏÏÏÏÏÏ
$58,961
12,193
71,154
6,350
Total embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$77,504
(1) The total amount embezzled during 2005 was $18,543,000 and the Company incurred $1,500,000 of
professional fees and expenses as a result of the embezzlement. Accordingly, the total embezzled funds
and related expenses in 2005 were $20,043,000.
The Company promptly advised the United States Securities and Exchange Commission (""SEC'') when
it became aware of the embezzlement. The SEC promptly obtained a freeze order on Nelson's assets
F-14
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
(including assets held by entities controlled by him) and a Receiver was appointed to collect those assets. The
United States attorney for the Northern District of Texas obtained an indictment against Nelson and
investigation of this matter continues.
The Company understands that the Receiver will ultimately liquidate the assets and propose a plan to
distribute the proceeds. While the Company believes it has a claim for at least the full amount embezzled,
other creditors have or may assert claims on the assets held by the Receiver. As a result, recovery by the
Company from the Receiver is uncertain as to timing and amount, if any. Recoveries, if any, will be
recognized when they are considered collectable.
The Ñnancial statements and related Ñnancial and statistical data contained in this Report have been
restated to provide for, net of related tax eÅects, (1) the eÅects of losses incurred as a result of the
embezzlement and (2) the eÅects of the correction of other errors that are immaterial both individually and in
the aggregate. The eÅects of the embezzlement and other adjustments on the company's Ñnancial position
follow:
Previously
Reported
As of December 31,
EÅects of
Adjustment for
Embezzlement
EÅects of
Other
Adjustments
(In thousands)
Restated
$1,400,848
(571,973)
828,875
101,326
1,322,911
2,754
162,040
315,372
415,489
$(55,211)
1,348
(53,863)
(2,270)
(56,133)
1,311
(22,159)
(20,848)
(35,285)
$(6,866)
(3,127)
(9,993)
Ì
(9,993)
166
594
760
(6,492)
$1,338,771
(573,752)
765,019
99,056
1,256,785
4,231
140,475
295,284
373,712
11,611
1,007,539
Ì
(35,285)
(4,261)
(10,753)
7,350
961,501
2004:
Property and equipment:
At costÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accumulated depreciation ÏÏÏÏÏÏÏÏÏ
NetÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Federal and state income taxes payable
Deferred tax liabilities, net ÏÏÏÏÏÏÏÏÏÏ
Liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Retained earnings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accumulated other comprehensive
income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003:
Federal and state income taxes
receivable ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
12,667
$ (1,044)
$ (170)
$
11,453
Property and equipment:
At costÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accumulated depreciation ÏÏÏÏÏÏÏÏÏ
NetÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred tax liabilities, net ÏÏÏÏÏÏÏÏÏÏ
Liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Retained earnings ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accumulated other comprehensive
income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Stockholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1,161,536
(467,905)
693,631
51,179
1,084,114
143,309
264,365
317,627
6,934
819,749
F-15
(38,240)
890
(37,350)
(146)
(38,540)
(15,044)
(15,044)
(23,496)
Ì
(23,496)
(4,992)
(891)
(5,883)
Ì
(6,053)
386
386
(3,894)
(2,545)
(6,439)
1,118,304
(467,906)
650,398
51,033
1,039,521
128,651
249,707
290,237
4,389
789,814
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
The eÅects of the embezzlement and other adjustments on the Company's results of operations and cash
Öows follow:
2004:
Depreciation, depletion, amortization and
impairmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrative ÏÏÏÏÏÏ
Other (including gain or loss on sale of
assets)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Embezzled funds expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income before income taxes ÏÏÏÏÏÏÏÏÏÏÏ
Income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Per common share:
Year Ended December 31,
EÅects of
EÅects of
Other
Adjustment for
Adjustments
Embezzlement
Previously
Reported
(In thousands, except per share amounts)
Restated
$ 119,395
32,007
$
(461)
(24)
$ 3,866
Ì
$ 122,800
31,983
1,655
Ì
171,214
171,894
63,161
108,733
Ì
19,122
(18,637)
(18,637)
(6,848)
(11,789)
(244)
Ì
(4,110)
(4,110)
(1,512)
(2,598)
(0.02)
(0.02)
1,411
19,122
148,467
149,147
54,801
94,346
0.57
0.56
Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
0.65
0.64
(0.07)
(0.07)
Net cash provided by (used in):
Operating activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Acquisitions ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Purchases of property and equipment ÏÏÏÏ
222,289
(222,537)
32,514
191,560
(19,098)
19,098
(2,127)
(16,971)
Ì
Ì
Ì
Ì
203,191
(203,439)
30,387
174,589
F-16
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
2003:
Depreciation, depletion, amortization and
impairmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Selling, general and administrative ÏÏÏÏÏÏ
Other (including gain or loss on sale of
assets)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Embezzled funds expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income before income taxes and
cumulative eÅect of change in
accounting principle ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income before cumulative eÅect of
change in accounting principleÏÏÏÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Per common share:
Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Net cash provided by (used in):
Year Ended December 31,
EÅects of
EÅects of
Other
Adjustment for
Adjustments
Embezzlement
Previously
Reported
(In thousands, except per share amounts)
Restated
$
97,998
27,709
$
(450)
(24)
$ 3,286
Ì
$ 100,834
27,685
4,626
Ì
87,190
89,884
32,996
56,888
56,419
0.35
0.34
Ì
17,849
(17,375)
(17,375)
(6,378)
(10,997)
(10,997)
(0.07)
(0.07)
(247)
Ì
(3,533)
(3,533)
(1,298)
(2,235)
(2,235)
(0.01)
(0.01)
4,379
17,849
66,282
68,976
25,320
43,656
43,187
0.27
0.26
Operating activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Purchases of property and equipment ÏÏÏÏ
162,776
(154,603)
116,626
(17,825)
17,825
(17,825)
Ì
Ì
Ì
144,951
(136,778)
98,801
3. Acquisitions
2005 Acquisitions
Key Energy Services, Inc. Ì On January 15, 2005, the Company purchased land drilling assets from Key
Energy Services, Inc. for $61.8 million. The assets included 25 active and 10 stacked land-based drilling rigs,
related drilling equipment, yard facilities and a rig moving Öeet consisting of approximately 45 trucks and
100 trailers. The transaction was accounted for as an acquisition of assets and the purchase price was allocated
among the assets acquired based on their estimated fair market values.
Other Ì On June 17, 2005, the Company acquired one land-based drilling rig for $3.6 million and on
September 29, 2005, the Company acquired Ñve land-based drilling rigs and related drilling equipment for
$8.2 million. The transactions were accounted for as acquisitions of assets and the purchase price was
allocated among the assets acquired based on their estimated fair market values.
2004 Acquisition
TMBR/Sharp Drilling, Inc. Ì On February 11, 2004, the Company completed its acquisition of TMBR,
a Texas corporation, in which one of its wholly-owned subsidiaries acquired 100% of the remaining
outstanding shares of TMBR. Operations of TMBR subsequent to February 11, 2004, are included in the
Company's consolidated Ñnancial statements. The transaction was accounted for as a business combination
and the purchase price was allocated among the assets acquired and liabilities assumed based on their
F-17
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
estimated fair market values. The assets of TMBR included 18 land-based drilling rigs and related equipment,
shop facilities, equipment yards and their oil and natural gas properties.
The purchase price was calculated as follows (restated (See Note 2), in thousands, except per share data
and exchange ratio):
Cash of $9.09 per share for the 4,447 TMBR shares outstanding at February 11,
2004, excluding the 1,059 TMBR shares owned by Patterson-UTI ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 40,423
Patterson-UTI shares issued at $17.82 per share (4,447 TMBR shares X .624332
exchange ratio X $17.82)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1,059 TMBR shares previously acquired by the Company ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Acquisition costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Less: Cash acquired ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
49,476
19,771
10,511
(7,909)
Total purchase price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$112,272
The purchase price was allocated among assets acquired and liabilities assumed based on their estimated
fair market values as follows (restated (See Note 2), in thousands):
Current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Fixed assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other long term assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred tax assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
GoodwillÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Current liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other long term liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred tax liabilityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
7,181
60,784
172
13,080
48,020
(7,080)
(1,090)
(8,795)
Total purchase allocation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$112,272
The Company acquired TMBR to increase its productive asset base in the Permian Basin, which is one of
the most active land drilling regions in the U.S. TMBR was well established in the contract drilling industry
and maintained favorable customer relationships. Goodwill was recognized in the transaction as a result of
these factors.
The following represents pro-forma unaudited Ñnancial information as if the acquisition had been
completed on January 1, 2003 (in thousands, except per share amounts):
Revenue ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Income before cumulative eÅect of change in accounting principle ÏÏÏÏÏ
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Earnings per share:
Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Restated (See Note 2)
2003
2004
$1,005,357
94,047
94,047
$818,774
45,430
44,961
$
$
0.57
0.56
$
$
0.28
0.27
F-18
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
2003 Acquisitions
SEI Drilling Company Ì On January 31, 2003, the Company acquired four land-based drilling rigs and
related equipment from SEI Drilling Company for $6.0 million in cash. The transaction was accounted for as
an acquisition of assets and the purchase price was allocated among the assets acquired based on their
estimated fair market values.
Mesa Drilling, Inc. Ì On February 7, 2003, the Company acquired three land-based drilling rigs, a yard
and other related equipment from Mesa Drilling, Inc. and related entities for $10.5 million in cash. The
transaction was accounted for as an acquisition of assets and the purchase price was allocated among the assets
acquired based on their estimated fair market values.
Other Ì On April 28, 2003, the Company acquired two land-based drilling rigs for $3.9 million in cash.
The transaction was accounted for as an acquisition of assets and the purchase price was allocated among the
assets acquired based on their estimated fair market values.
Hexadyne Drilling Corporation Ì On May 30, 2003, the Company acquired seven land-based drilling
rigs and related equipment from Hexadyne Drilling Corporation for $10.1 million in cash. The transaction was
accounted for as an acquisition of assets and the purchase price was allocated among the assets acquired based
on their estimated fair market values.
Fort Drilling LLC Ì On November 17, 2003, the Company acquired three land-based drilling rigs, a
shop facility and related equipment from Fort Drilling LLC for $7.2 million in cash. The transaction was
accounted for as an acquisition of assets and the purchase price was allocated among the assets acquired based
on their estimated fair market values.
Other Ì In addition to the above mentioned acquisitions, the Company spent approximately $3.1 million
on other acquisitions of assets and costs associated with the acquisitions completed during 2003.
4. Comprehensive Income
The following table illustrates the Company's comprehensive income including the eÅects of foreign
currency translation adjustments for the years ended December 31, 2005, 2004 and 2003 (in thousands):
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other comprehensive income:
Foreign currency translation adjustment related to Canadian
Restated (See Note 2)
2005
2004
2003
$372,740
$94,346
$43,187
operationsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1,215
2,961
5,553
Comprehensive incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$373,955
$97,307
$48,740
F-19
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
5. Property and Equipment
Property and equipment consisted of the following at December 31, 2005 and 2004 (in thousands):
Equipment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas properties ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
BuildingsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Land ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,633,911
79,079
22,490
5,611
2005
Restated
(See Note 2)
2004
$1,239,519
82,711
12,892
3,649
Less accumulated depreciation and depletion ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1,741,091
(687,246)
1,338,771
(573,752)
$1,053,845
$ 765,019
6. Goodwill
Goodwill is evaluated to determine if the fair value of the asset has decreased below its carrying value. At
December 31, 2005 the Company performed its annual goodwill evaluation and determined no adjustment to
impair goodwill was necessary. Goodwill as of December 31, 2005 and 2004 are as follows (in thousands):
Restated
(See Note 2)
2004
2005
Drilling:
Goodwill at beginning of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Goodwill in TMBR ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$89,092
Ì
Ì
$41,069
48,020
3
Goodwill at end of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
89,092
89,092
Drilling and completion Öuids:
Goodwill at beginning of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Changes to goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Goodwill at end of period ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
9,964
Ì
9,964
9,964
Ì
9,964
Total goodwill ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$99,056
$99,056
7.
Investment in Equity Securities
As a result of the Company increasing its ownership of TMBR from 19.5% to 100% in 2004, the
Company's consolidated Ñnancial statements for 2003 were previously restated to provide for the retroactive
application of the equity method of accounting for the investment in TMBR.
F-20
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
The following tables present the eÅects of all restatements for the year ended December 31, 2003 (in
thousands, except per share amounts):
Other income (loss) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred income tax expense ÏÏÏÏÏÏÏÏÏ
Net incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Comprehensive income, net of taxÏÏÏÏÏ
Net income per common share:
Previously
Reported
on Cost
Basis
EÅects of
Adjustment
to Equity
Method
$
143
$17,274
$55,326
$65,689
$1,727
$ 634
$1,093
$ (497)
EÅects of
Adjustment for
Embezzlement
EÅects of
Other
Adjustments
Ì
$
$ (6,615)
$(10,997)
$(10,997)
$ Ì
$(1,297)
$(2,235)
$(5,455)
Restated
$ 1,870
$ 9,996
$43,187
$48,740
Basic ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Diluted ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
$
0.34
0.34
$ 0.01
$ 0.01
$
$
(0.07)
(0.07)
$ (0.01)
$ (0.01)
$ 0.27
$ 0.26
8. Accrued Expenses
Accrued expenses consisted of the following at December 31, 2005 and 2004 (in thousands):
2005
2004
Salaries, wages, payroll taxes and beneÑts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Workers' compensation liability ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Sales, use and other taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Insurance, other than workers' compensation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 33,816
47,107
9,484
11,365
10,704
$21,245
38,677
5,863
7,061
6,317
$112,476
$79,163
9. Asset Retirement Obligation
Statement of Financial Accounting Standards No. 143, ""Accounting for Asset Retirement Obligations,''
(""SFAS 143''), requires that the Company record a liability for the estimated costs to be incurred in
connection with the abandonment of oil and natural gas properties in the future. The following table describes
the changes to the Company's asset retirement obligations during 2005 and 2004 (in thousands):
2005
2004
Balance at beginning of yearÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Liabilities incurred* ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Liabilities settled ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Accretion expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$2,358
101
(808)
74
$1,163
1,277
(153)
71
Asset retirement obligation at end of year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,725
$2,358
* The 2004 amount includes $1,091 of liabilities assumed in the acquisition of TMBR.
As a result of the Company's adoption of SFAS 143, a cumulative eÅect of change in accounting
principle of approximately $469,000, net of tax, was recorded in the Ñrst quarter of 2003.
F-21
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
10. Notes Payable
The Company replaced its prior credit facility in December 2004 with a Ñve-year, $200 million unsecured
revolving line of credit (""LOC''). Interest is to be paid on outstanding LOC balances at a Öoating rate ranging
from LIBOR plus 0.625% to 1.0% or the prime rate. This arrangement includes various fees, including a
commitment fee on the average daily unused amount (0.15% at December 31, 2005). There are customary
restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to
capitalization ratio and a minimum interest coverage ratio. The Company does not expect that the restrictions
and covenants will restrict its ability to operate or react to opportunities that might arise. Availability under the
LOC is reduced by outstanding letters of credit which totaled $56 million at December 31, 2005. There were
no outstanding borrowings under the LOC at December 31, 2005. Costs of approximately $445,000 were
expensed in 2004 to terminate the previous $100 million credit facility.
11. Commitments, Contingencies and Other Matters
The Company maintains letters of credit in the aggregate amount of $56.0 million for the beneÑt of
various insurance companies as collateral for retrospective premiums and retained losses which may become
payable under the terms of the underlying insurance contracts. These letters of credit expire variously during
each calendar year. No amounts have been drawn under the letters of credit.
Contingencies Ì The Company's contract services and oil and natural gas exploration and production
operations are subject to inherent risks, including blowouts, cratering, Ñre and explosions which could result in
personal injury or death, suspended drilling operations, damage to, or destruction of equipment, damage to
producing formations and pollution or other environmental hazards.
As a protection against these hazards, the Company maintains general liability insurance coverage of
$2.0 million per occurrence with $4.0 million of aggregate coverage and excess liability and umbrella
coverages up to $75.0 million per occurrence and in the aggregate. The Company maintains a $1.0 million per
occurrence deductible on its workers' compensation insurance and its general liability insurance coverages.
These levels of self-insurance expose the Company to increased operating costs and risks.
We have signed non-cancelable commitments to purchase $118 million of equipment to be received
throughout 2006.
Net income for the year ended December 31, 2005 includes a charge of $4.2 million related to the
Ñnancial failure of a workers' compensation insurance carrier that had provided coverage for the Company in
prior years.
The Company believes it is adequately insured for public liability and property damage to others with
respect to its operations. However, such insurance may not be suÇcient to protect the Company against
liability for all consequences of well disasters, extensive Ñre damage, or damage to the environment. The
Company also carries insurance to cover physical damage to, or loss of, its rigs; however, it does not carry
insurance against loss of earnings resulting from such damage or loss.
In December 2005, two purported derivative actions were Ñled in Texas state court in Scurry County,
Texas, against the directors of the Company, alleging that the directors breached their Ñduciary duties to the
Company as a result of alleged failure to timely discover the embezzlement. The Board of Directors formed a
special litigation committee to review and inquire about these allegations and recommend the Company's
response, if any. Further legal proceedings in these suits have been stayed pending completion of the work of
the special litigation committee. The lawsuits seek recovery on behalf of and for the Company and do not seek
recovery from the Company.
F-22
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
The Company is party to various other 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 eÅect on its Ñnancial condition.
Other Matters Ì EÅective January 29, 2004, the Company entered into Change in Control Agreements
with its Chairman of the Board, Chief Executive OÇcer, President, two Senior Vice Presidents and Nelson
(the ""Key Employees''). On November 3, 2005, Nelson resigned, which resulted in the expiration of his
Change in Control Agreement. Each Change in Control Agreement generally has a three-year term with
automatic twelve month renewals unless the Company notiÑes 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 deÑned in the Change in Control Agreements),
then the Key Employee shall be entitled to, among other things,
‚ 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 Ñscal years immediately
preceding a change in control (such bonus payment prorated for the portion of the Ñscal year preceding
the termination date);
‚ a payment equal to 2.5 times (in the case of the Chairman of the Board, Chief Executive OÇcer and
President and Chief Operating OÇcer) or 1.5 times (in the case of the Senior Vice Presidents) of the
sum of (i) the highest annual salary in eÅect for such Key Employee and (ii) the average of the three
annual bonuses earned by the Key Employee for the three Ñscal years preceding the termination date;
and
‚ continued coverage under the Company's welfare plans for up to three years (in the case of the
Chairman of the Board, Chief Executive OÇcer and President and Chief Operating OÇcer) or two
years (in the case of the Senior Vice Presidents).
Each Change in Control Agreement provides the Key Employee with a full gross-up payment for any
excise taxes imposed on payments and beneÑts received under the Change in Control Agreements or
otherwise, including other taxes that may be imposed as a result of the gross-up payment.
12. Stockholders' Equity
During the second quarters of 2004 and 2005 and third quarter of 2005, the Company granted restricted
shares of the Company's common stock (the ""Restricted Shares'') to certain key employees under the
Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended, and the 2005 Plan. As required by
APB 25, the Restricted Shares were valued based upon the market price of the Company's common stock on
the date of the grant. The 2005 grants consisted of 305,000 restricted shares with a weighted average grant
date fair value of $26.37 per share. The resulting value is being amortized over the vesting period of the stock.
For the years ended December 31, 2005 and 2004, compensation expense of $1.8 million and $773,000, net of
$327,000 and $5,000 of forfeitures and of $1.0 million and $449,000 of taxes, respectively, was included as a
reduction in net income.
On June 7, 2004, the Company's Board of Directors authorized a stock buyback program for the purchase
of up to $30 million of the Company's outstanding common stock. During the second quarter of 2004, the
Company purchased 100,000 shares of its common stock in the open market for approximately $1.5 million
(adjusted to reÖect the two-for-one stock split on June 30, 2004). During the fourth quarter of 2005, the
Company purchased 355,000 shares of its common stock in the open market for approximately $12.2 million.
These shares are included in treasury stock. On March 27, 2006, the Company's Board of Directors increased
the stock buyback program to allow the future purchases of up to $200 million of the Company's outstanding
common stock.
F-23
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
On April 28, 2004, the Company's Board of Directors authorized a two-for-one stock split in the form of a
stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. In connection
with the two-for-one stock split, an adjustment was made to reclassify an amount from retained earnings to
common stock to account for the par value of the common stock issued as a stock dividend. This adjustment
had no overall eÅect on equity. The prior year balance sheet was not restated as a result of this transaction;
however, historical earnings per share amounts included in the Consolidated Statements of Income and
elsewhere in this Report have been restated as if the two-for-one stock split had occurred on January 1, 2003.
On April 28, 2004, the Company's Board of Directors approved the initiation of a quarterly cash dividend
of $0.02 on each share of its common stock which was paid on June 2, 2004. Quarterly dividends in the
amount of $0.02 per share were also paid on September 1, 2004 and December 1, 2004. Total dividends paid in
2004 were approximately $10 million. In February 2005, the Company's Board of Directors approved an
increase in the quarterly cash dividend on the Company's common stock to $0.04 per share from $0.02 per
share. Quarterly cash dividends in the amount of $0.04 per share were paid on March 4, 2005, June 1, 2005,
September 1, 2005 and December 1, 2005. Total cash dividends in 2005 were approximately $27.3 million.
The next quarterly cash dividend is to be paid to holders of record on March 15, 2006 and paid on March 30,
2006. The amount and timing of all future dividend payments is subject to the discretion of the Board of
Directors and will depend upon business conditions, results of operations, Ñnancial condition, terms of the
Company's credit facilities and other factors.
In February 2004, the Company completed its acquisition of TMBR in which one of its wholly-owned
subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of
$32.5 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction)
and the issuance of 2.78 million shares of the Company's common stock valued at $17.82 per share (adjusted
to reÖect the two-for-one stock split on June 30, 2004). The assets of TMBR included 18 land-based drilling
rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The
transaction was accounted for as a business combination and the purchase price was allocated among the
assets acquired and liabilities assumed based on their estimated fair market values (see Note 3).
13. Stock Options and Warrants
Employee and Non-Employee Director Stock Option Plans Ì The Company has eight stock option plans
of which one has shares available for grant. The remaining six plans are dormant and the Company does not
F-24
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
intend to grant any further options under such plans. At December 31, 2005, the Company's stock option plans
were as follows:
Plan Name
Options
Authorized
for Grant
Options
Outstanding
Options
Available
for Grant
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive
Plan (""2005 Plan'')(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
6,250,000
Ì 5,464,217
Patterson-UTI Energy, Inc. Amended and Restated 1997
Long-Term Incentive Plan, as amended (""1997 Plan'')
Amended and Restated Patterson-UTI Energy, Inc. 2001
Ì 5,010,603
Long-Term Incentive Plan (""2001 Plan'')ÏÏÏÏÏÏÏÏÏÏÏÏ
Ì
888,304
Amended and Restated Non-Employee Director Stock
Option Plan of Patterson-UTI Energy, Inc. (""Non-
Employee Director Plan'') ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1997 Stock Option Plan of DSI Industries, Inc. (""DSI
Plan'')ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Amended and Restated Patterson-UTI Energy, Inc. 1996
Employee Stock Option Plan (""1996 Plan'') ÏÏÏÏÏÏÏÏÏ
Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan,
as amended (""1993 Plan'') ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Ì
Ì
Ì
Ì
200,000
536
95,800
142,800
Ì
Ì
Ì
Ì
Ì
Ì
(1) Plan is for the beneÑt of employees of the Company, including oÇcers and directors of the Company.
The Company's active plan is the 2005 Plan. A summary of this plan is set forth below.
2005 Plan
‚ Administered by the Compensation Committee of the Board of Directors.
‚ All employees including oÇcers and directors are eligible for awards.
‚ Vesting schedule is set by the Compensation Committee, however, typically awards vest over 4 years.
‚ The Compensation Committee sets the term of the award except that no option can have a term of
longer than 10 years.
‚ The awards granted under the plan, unless otherwise stated in the grant thereof, do not vest upon a
change of control as deÑned in the plan.
‚ All options granted under the plan are granted with an exercise price equal to or greater than the fair
market value of the Company's common stock at the time the option is granted.
‚ The plan provides for awards of incentive stock options, non-incentive stock options, tandem and
freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance
share awards, performance unit awards and dividend equivalents.
1997 Plan Ì Options granted under the 1997 Plan vest over three or Ñve years as dictated by the
Compensation Committee. These options typically had terms of 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. Restricted
Stock Awards granted under the 1997 Plan vest over four years.
2001 Plan Ì Options granted under the 2001 Plan vest over Ñve years as dictated by the Compensation
Committee. These options had terms of 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. Restricted Stock Awards granted
under the 2001 Plan vest over four years.
F-25
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
Non-Employee Director Plan Ì Options granted under the Non-Employee Director Plan vest on the Ñrst
anniversary of the option grant. Non-Employee Director Plan options have Ñve year terms. 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.
DSI Plan Ì Options granted under the DSI plan typically vested at a rate of 33% per year with ten year
terms. 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.
1996 Plan Ì Options granted under the 1996 plan vested over one, four and Ñve years as dictated by the
Compensation Committee. These options had terms of Ñve and ten years as dictated by the Compensation
Committee. 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.
1993 Plan Ì Options granted under the 1993 Plan, typically had terms of 10 years and vested over Ñve
years in 20% increments beginning at the end of the Ñrst year. These options vest in the event of a change of
control as deÑned in the plan. 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.
A summary of the status of the Company's stock options issued as of December 31, 2005, 2004 and 2003
and the changes during each of the years then ended are presented below (in thousands, except weighted
average exercise price):
2005
2004
2003
No. of
Shares of
Underlying
Options
Weighted
Average
Exercise
Price
No. of
Shares of
Underlying
Options
Weighted
Average
Exercise
Price
No. of
Shares of
Underlying
Options
Weighted
Average
Exercise
Price
Outstanding at beginning of
year ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
GrantedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Exercised ÏÏÏÏÏÏÏÏÏÏÏÏÏ
Surrendered/Expired ÏÏÏÏ
Outstanding at end of year
Exercisable at end of year
10,006
675
(4,044)
(299)
6,338
4,809
$12.24
24.63
10.75
15.23
$14.37
$13.33
12,276
640
(2,852)
(58)
10,006
6,377
$10.31
19.19
5.55
8.76
$12.24
$11.68
12,277
1,830
(1,736)
(95)
12,276
5,972
$ 8.81
16.24
5.92
9.99
$10.31
$ 8.15
F-26
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
The following table summarizes information about stock options outstanding at December 31, 2005:
Range of Exercise Prices
$1.5625 to $ 2.50 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2.51 to $ 5.00 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
5.01 to $ 7.50 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
$
7.51 to $10.00 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 10.01 to $12.50 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 12.51 to $15.00 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 15.01 to $24.63 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Options Outstanding
Options Exercisable
Weighted
Average
Remaining
Contracted
Life
3.25
2.16
1.65
5.46
2.05
6.58
7.68
6.70
Number
Outstanding
136,100
41,300
53,436
1,256,470
42,500
1,849,904
2,958,333
6,338,043
Weighted
Average
Exercise
Price
$ 2.24
$ 4.94
$ 7.36
$ 8.01
$11.48
$13.43
$18.53
Number
Exercisable
136,100
41,300
53,436
879,170
42,500
1,680,771
1,976,111
Weighted
Average
Exercise
Prices
$ 2.24
$ 4.94
$ 7.36
$ 8.03
$11.48
$13.34
$16.81
$14.37
4,809,388
$13.33
Pro Forma Stock-Based Compensation Disclosure Ì Pro forma information in accordance with
SFAS 123 regarding net income and earnings per share, as described in Note 1, has been determined as if the
Company had accounted for its employee stock options under the fair value method as deÑned in that
statement. The fair value of each stock option granted is estimated on the date of grant using the Black-
Scholes option valuation model with the following weighted-average assumptions for grants in 1996 through
2005 respectively; dividend yield of 0.65% for all 2005 grants, 0.06% for all 2004 grants and 0.00% for all other
grants; risk-free interest rates are diÅerent for each grant and range from 2.18% to 7.02%; the expected term
ranges from 3 to 6 years; and a volatility of 38.68% for all 1996 grants, 35.97% for all 1997 grants, 51.08% for
all 1998 grants, 61.97% for all 1999 grants, 67.71% for all 2000 grants, 68.33% for all 2001 grants, 63.02% for
all 2002 grants, 44.04% for all 2003 grants, 36.84% for all 2004 grants and 26.95% for all 2005 grants. The
eÅects of applying SFAS 123 in this pro forma disclosure are not indicative of future amounts. SFAS 123 does
not apply to awards prior to 1996.
Stock Purchase Warrants Ì In December 2001, the Company issued 650,000 warrants exercisable at
$13.375 per share as partial consideration for the purchase of 17 drilling rigs and related equipment from
Cleere Drilling Company. The warrants were fully exercisable at the date of issuance. All of the warrants were
exercised in December 2004.
F-27
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
Tabular Summary Ì The following table summarizes information regarding the Company's stock
options and warrants granted under the provisions of the aforementioned plans as well as stock options and
warrants issued pursuant to transactions described above (in thousands, except weighted average exercise
prices):
Weighted
Average
Exercise Price
Shares
Granted
2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Exercised
2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Surrendered
2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Outstanding at Year End
675
640
1,830
4,044
3,502
1,941
299
58
95
2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
6,338
10,006
12,926
Exercisable at Year End
2005 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2003 ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
4,809
6,377
6,622
$24.63
$19.19
16.24
$10.75
$ 7.00
6.46
$15.23
$ 8.76
9.99
$14.37
$12.24
10.47
$13.33
$11.68
8.66
14. Leases
The Company incurred rent expense, consisting primarily of daily rental charges for the use of drilling
equipment, of $10.5 million, $9.1 million and $8.6 million, for the years 2005, 2004 and 2003, respectively.
The Company's obligations under non-cancelable operating lease agreements are not material to the
Company's operations.
F-28
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
15.
Income Taxes
Components of the income tax provision applicable for Federal, state and foreign income taxes are as
follows (in thousands):
Federal income tax expense (beneÑt):
CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$174,635
14,182
$32,686
12,366
$14,073
7,794
Restated (See Note 2)
2005
2004
2003
State income tax expense (beneÑt):
CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Foreign income tax expense (beneÑt):
CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
188,817
45,052
21,867
13,045
1,431
14,476
7,238
1,488
8,726
2,031
1,555
3,586
5,235
928
6,163
1,233
(487)
746
18
2,689
2,707
Total:
CurrentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
194,918
17,101
39,952
14,849
15,324
9,996
Total income tax expenseÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$212,019
$54,801
$25,320
The diÅerence between the statutory Federal income tax rate and the eÅective income tax rate is
summarized as follows:
Restated
(See Note 2)
2003
2004
2005
Statutory tax rate ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
State income taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Permanent diÅerences ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
35.0% 35.0% 35.0%
1.6
1.8
0.4
(0.6)
(0.3)
0.1
1.5
0.8
(0.6)
EÅective tax rateÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
36.3% 36.7% 36.7%
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 diÅerences 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, 2005 to be realized as a result of the reversal during
the carryforward period of existing taxable temporary diÅerences giving rise to deferred tax liabilities and the
generation of taxable income in the carryforward period; therefore, no valuation allowance is necessary.
F-29
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
The tax eÅect of signiÑcant temporary diÅerences representing deferred tax assets and liabilities and
changes therein were as follows (in thousands):
December 31,
2005
Net
Change
December 31,
2004
Net
Change
Restated (See Note 2)
December 31,
2003
Net
Change
January 1,
2003
Deferred tax assets:
Current:
Federal net operating
loss carryforwardsÏÏ
$
1,870
$
Ì $
1,870
$
1,870
$
Ì $
Ì $
Ì
Workers'
compensation
allowance ÏÏÏÏÏÏÏÏ
AMT credit ÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Non-current:
Federal net operating
loss carryforwardsÏÏ
AMT credit ÏÏÏÏÏÏÏÏ
Federal beneÑt of
foreign deferred tax
liabilities ÏÏÏÏÏÏÏÏÏ
Federal beneÑt of
state deferred tax
liabilities ÏÏÏÏÏÏÏÏÏ
Embezzled funds
expense ÏÏÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total deferred tax assets ÏÏ
Deferred tax liabilities:
Current:
19,461
Ì
11,364
32,695
4,584
Ì
4,386
8,970
14,877
Ì
6,978
23,725
1,545
(602)
1,238
4,051
13,332
602
5,740
19,674
6,159
Ì
(1,775)
7,173
602
7,515
4,384
15,290
2,245
118
(1,870)
Ì
4,115
118
4,115
118
Ì
Ì
Ì
Ì
Ì
Ì
8,196
1,488
6,708
933
5,775
2,019
3,756
4,232
717
3,515
421
3,094
1,275
1,819
Ì
937
15,728
48,423
(22,178)
174
(21,669)
(12,699)
22,178
763
37,397
61,122
7,193
763
13,543
17,594
14,985
Ì
23,854
43,528
6,713
Ì
10,007
14,391
8,272
Ì
13,847
29,137
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(6,313)
1,421
(7,734)
(4,509)
(3,225)
(3,225)
Ì
Non-current:
Property and
equipment basis
diÅerence ÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Total deferred tax
(179,725)
(5,191)
(6,381)
(663)
(173,344)
(4,528)
(25,534)
167
(147,810)
(4,695)
(16,683)
(4,795)
(131,127)
100
(184,916)
(7,044)
(177,872)
(25,367)
(152,505)
(21,478)
(131,027)
liabilities ÏÏÏÏÏÏÏÏÏÏÏÏÏ
(191,229)
(5,623)
(185,606)
(29,876)
(155,730)
(24,703)
(131,027)
Net deferred tax liabilityÏÏ
$(142,806)
$(18,322)
$(124,484)
$(12,282)
$(112,202)
$(10,312)
$(101,890)
Management expects to deduct accumulated net embezzlement losses in the Company's 2005 tax
returns, which corresponds with the period in which the embezzlement was detected.
F-30
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
Other deferred tax assets consist primarily of various allowance accounts and tax deferred expenses
expected to generate future tax beneÑt of approximately $12 million. Other deferred tax liabilities consist
primarily of receivables from insurance companies and tax deferred income not yet recognized for tax
purposes.
For tax purposes, the Company has available at December 31, 2005, Federal net operating loss
carryforwards of approximately $11 million and $118,000 of alternative minimum tax credit carryforwards.
These carryforwards are attributable to the acquisition of TMBR in February 2004.
The net operating loss carryforwards, if unused, are scheduled to expire as follows: 2006 Ì $1 million,
2011 Ì $2 million, 2018 Ì $4 million and 2019 Ì $4 million. The alternative minimum tax credit may be
carried forward indeÑnitely.
16. Employee BeneÑts
The Company maintains a 401(k) plan for all eligible employees. The Company's operating results
include expenses of approximately $2.7 million in 2005, $2.2 million in 2004 and $1.5 million in 2003 for the
Company's discretionary contributions to the plan.
17. Business Segments
The Company conducts its business through four distinct operating segments: contract drilling of oil and
natural gas wells, pressure pumping services and drilling and completion Öuids services to operators in the oil
and natural gas industry, and the exploration, development, acquisition and production of oil and natural gas.
Each of these segments represents a distinct type of business based upon the type and nature of services and
products oÅered. These segments have separate management teams which report to the Company's chief
executive oÇcer and have distinct and identiÑable revenues and expenses.
Contract Drilling Ì The Company markets its contract drilling services to major and independent oil and
natural gas operators. As of December 31, 2005, the Company owned 403 drilling rigs, of which 156 of the
drilling rigs were based in the Permian Basin region, 53 in South Texas, 42 in the Ark-La-Tex region and
Mississippi, 88 in the Mid-Continent region, 46 in the Rocky Mountain region and 18 in Western Canada.
The Company operated 307 of its drilling rigs in 2005.
Pressure Pumping Ì The Company provides pressure pumping services primarily in the Appalachian
Basin. Pressure pumping services consist primarily of well stimulation and cementing for the completion of
new wells and remedial work on existing wells. Well stimulation involves processes inside a well designed to
enhance the Öow of oil, natural gas, or other desired substances from the well. Cementing is the process of
inserting material between the hole and the pipe to center and stabilize the pipe in the hole.
Drilling and Completion Fluids Ì The Company provides drilling Öuids, completion Öuids and related
services to oil and natural gas operators oÅshore in the Gulf of Mexico and on land in Texas, Southeastern
New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion Öuids are used by oil
and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells.
The drilling Öuids operations were added by the Company during 1998 with its acquisition of two companies
with operations in Texas, Southeastern New Mexico, Oklahoma and Colorado. The Company's services were
expanded to include completion Öuids in October 2000 with the acquisition of the drilling and completion
Öuids division of Ambar, Inc., which had operations in the coastal areas of Texas, Louisiana and in the Gulf of
Mexico.
Oil and Natural Gas Ì The Company is engaged in the development, exploration, acquisition and
production of oil and natural gas.
F-31
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
The following tables summarize selected Ñnancial information relating to the Company's business
segments (in thousands):
Years Ended December 31,
2005
Restated (See Note 2)
2003
2004
Revenues:
Contract drilling(a) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids(b) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,488,485
93,144
122,309
39,616
$ 815,683
66,654
90,858
33,867
$ 640,788
46,083
69,286
21,163
Total segment revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Elimination of intercompany revenues(a)(b)ÏÏÏÏÏÏÏÏ
1,743,554
1,007,062
(3,099)
(6,293)
777,320
(1,150)
Total revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,740,455
$1,000,769
$ 776,170
Income (loss) before income taxes:
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 572,562
21,664
11,947
13,405
$ 146,626
16,747
4,202
10,764
$
Corporate and otherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other charges(c) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Embezzled funds and related expenses(d) ÏÏÏÏÏÏÏÏÏÏ
Interest incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Interest expense ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
619,578
(14,223)
(4,016)
(20,043)
3,551
(516)
428
178,339
(10,750)
Ì
(19,122)
1,140
(695)
235
72,814
10,442
(1,920)
7,784
89,120
(7,441)
2,452
(17,849)
1,116
(292)
1,870
Income before income taxes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 584,759
$ 149,147
$
68,976
IdentiÑable assets:
Contract drilling ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Corporate and other(e)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,421,779
72,536
90,904
60,785
1,646,004
149,777
$ 961,873
49,145
62,970
62,984
1,136,972
119,813
$ 766,039
35,066
56,215
37,111
894,431
145,090
Total assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,795,781
$1,256,785
$1,039,521
Depreciation, depletion and impairment:
Contract drilling(d) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 131,740
7,094
2,368
14,456
Corporate and otherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
155,658
735
$ 101,779
5,112
2,156
13,309
122,356
444
$
87,255
3,774
2,279
7,082
100,390
444
Total depreciation, depletion and impairment ÏÏÏÏÏÏÏÏÏ
$ 156,393
$ 122,800
$ 100,834
F-32
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
Years Ended December 31,
2005
Restated (See Note 2)
2003
2004
Capital expenditures:
Contract drilling(d) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Pressure pumpingÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Drilling and completion Öuids ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Oil and natural gas ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Corporate and otherÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 329,073
25,508
3,042
17,163
5,308
$ 140,945
17,705
1,488
14,451
Ì
$
77,350
10,524
912
10,015
Ì
Total capital expenditures ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 380,094
$ 174,589
$
98,801
(a) Includes contract drilling intercompany revenues of approximately $2.8 million, $6.0 million and
$1.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.
(b) Includes drilling and completion Öuids intercompany revenues of approximately $298,000, $301,000 and
$56,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
(c) Other charges relate to decisions of the executive management group regarding corporate strategy, credit
risk, loss contingencies and restructuring activities. Due to the non-operating nature of these decisions,
the related charges have been separately presented and excluded from the results of speciÑc segments.
These charges are primarily related to the contract drilling segment.
(d) The Company's former CFO perpetrated an embezzlement over a period of more than Ñve years.
Embezzled funds expense includes adjustments to eliminate payments related to the embezzlement
previously capitalized as property and equipment and goodwill acquired. The related depreciation and
other amounts expensed have also been reversed from the Company's accounting records (See Note 2).
(e) Corporate assets primarily include cash on hand managed by the parent corporation and certain deferred
Federal income tax assets.
18. Quarterly Financial Information (unaudited)
On December 22, 2005, upon recommendation of Company management and the Audit Committee of its
Board of Directors, the Company announced that based on the results to date of its internal investigation into
the facts and circumstances surrounding the embezzlement by Nelson, the Company would restate previously
issued Ñnancial statements and amend its previously issued Annual Report on Form 10-K for the year ended
December 31, 2004 and Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 and
September 30, 2005. These restatements reÖect losses incurred as a result of payments made to or for the
beneÑt of Nelson that had been recognized in the Company's accounting records and previously issued
Ñnancial statements as payments for assets and services that were not received by the Company. Previously
issued Ñnancial statements have also been restated for the eÅects of the correction of other errors that are
immaterial both individually and in the aggregate. These other adjustments relate primarily to previously reported
property and equipment balances that resulted from our review of our property and equipment records and the underlying
physical assets in connection with investigation of the embezzlement. The Company has restated such financial statements,
and on March 17, 2006, the Company filed its amended Annual Report on Form 10-K/A and on March 27, 2006, the
Company filed its amended Quarterly Reports on Form 10-Q/A with the SEC. Quarterly financial information and the
F-33
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
related effects of the restatement due to the embezzlement and other adjustments for the years ended December 31, 2005
and 2004 is as follows (in thousands, except per share amounts):
Restated (See Note 2)
2nd
Quarter
3rd
Quarter
1st
Quarter
4th
Quarter
2005
Operating revenuesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $350,593
Operating income:
$389,922
$468,739
$531,201
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 94,252
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(1,381)
(1,038)
$122,416
$173,511
$
(4,717)
(1,048)
(4,721)
(1,344)
Ì
Ì
Ì
$ 91,833
$116,651
$167,446
$205,366
Net income:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 59,748
(872)
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(656)
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 77,665
$110,135
$
(2,978)
(661)
(2,981)
(849)
Ì
Ì
Ì
$ 58,220
$ 74,026
$106,305
$134,189
Earnings per share:
Basic:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
$
Diluted:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
$
0.35
(0.01)
$
$
Ì $
$
0.34
0.35
(0.01)
$
$
Ì $
$
0.34
0.46
(0.02)
$
$
Ì $
$
0.44
0.45
(0.02)
$
$
Ì $
$
0.43
0.64
(0.02)
$
$
Ì $
$
0.62
0.63
(0.02)
$
$
Ì $
$
0.61
Ì
Ì
Ì
0.78
Ì
Ì
Ì
0.77
1st
Quarter
Restated (See Note 2)
2nd
Quarter
3rd
Quarter
4th
Quarter
2004
Operating revenuesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $218,779
Operating income:
$234,510
$259,174
$288,306
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 32,510
(5,013)
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(927)
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 30,799
(3,470)
(1,002)
$ 47,408
(4,642)
(1,024)
$ 60,497
(5,512)
(1,157)
$ 26,570
$ 26,327
$ 41,742
$ 53,828
F-34
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
1st
Quarter
Restated (See Note 2)
2nd
Quarter
3rd
Quarter
4th
Quarter
Net income:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $ 20,682
(3,164)
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
(585)
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$ 19,607
(2,186)
(631)
$ 29,964
(2,921)
(645)
$ 38,480
(3,518)
(737)
$ 16,933
$ 16,790
$ 26,398
$ 34,225
Earnings per share:
Basic:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
$
Diluted:
As previously reported ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Adjustment for eÅects of embezzlement ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
Other adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ $
$
19. Concentrations of Credit Risk
0.12
(0.02)
$
$
Ì $
$
0.10
0.12
(0.02)
$
$
Ì $
$
0.10
0.12
(0.01)
$
$
Ì $
$
0.10
0.12
(0.01)
$
$
Ì $
$
0.10
0.18
(0.02)
$
$
Ì $
$
0.16
0.18
(0.02)
$
$
Ì $
$
0.16
0.23
(0.02)
Ì
0.20
0.23
(0.02)
Ì
0.20
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 that it places its demand deposits and temporary cash investments with high
credit quality Ñnancial institutions. At December 31, 2005 and 2004, the Company's demand deposits and
temporary cash investments consisted of the following (in thousands):
2005
2004
Deposits in FDIC and SIPC-insured institutions under $100,000 ÏÏÏÏÏÏÏÏ
Deposits in FDIC and SIPC-insured institutions over $100,000 ÏÏÏÏÏÏÏÏÏ
Deposits in Foreign Banks ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$
1,066
153,261
2,513
$
2,023
131,427
Ì
Less outstanding checks and other reconciling itemsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
156,840
(20,442)
133,450
(21,079)
Cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$136,398
$112,371
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 diversiÑcation of customers for which the Company provides drilling services. As is general
industry practice, the Company generally does not require customers to provide collateral. No signiÑcant
losses from individual contracts were experienced during the years ended December 31, 2005, 2004, or 2003.
The Company recognized bad debt expense for 2005, 2004 and 2003 of $1.2 million, $897,000 and $259,000,
respectively.
The carrying values of cash and cash equivalents, marketable securities and trade receivables approxi-
mate fair value due to the short-term maturity of these assets.
F-35
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Ì (Continued)
20. Related Party Transactions
Joint Operation of Oil and Natural Gas Properties Ì The Company operates certain oil and natural gas
properties in which certain of its aÇliated persons have participated, either individually or through entities
they control, in the prospects or properties in which the Company has an interest. These participations, which
have been on a working interest basis, have been in prospects or properties originated or acquired by Patterson-
UTI. At December 31, 2005, aÇliated persons were working interest owners in 254 of 305 total wells operated
by Patterson-UTI. Sales were made by Patterson-UTI at its cost, comprised of Patterson-UTI's costs of
acquiring and preparing the working interests for sale. These costs were paid by the working interest owners on
a pro rata basis based upon their working interest ownership percentage. The price at which working interests
were sold to aÇliated persons was the same price at which working interests were sold to unaÇliated persons.
The aÇliated persons earned oil and natural gas production revenue (net of royalty) of $15.5 million,
$13.8 million and $11.1 million from these properties in 2005, 2004 and 2003, respectively. These persons or
entities in turn paid for joint operating costs (including drilling and other development expenses) of
$9.5 million, $7.5 million and $7.9 million incurred in 2005, 2004 and 2003, respectively. These activities
resulted in a payable to the aÇliated persons of approximately $1.5 million and $1.2 million and a receivable
from the aÇliated persons of approximately $1.2 million and $856,000 at December 31, 2005 and 2004,
respectively.
Other Ì In 2005, 2004 and 2003, the Company paid approximately $424,000, $914,000 and $740,000,
respectively, to TMP Truck and Trailer LP (""TMP''), during the period it was owned by Thomas M.
Patterson (son of A. Glenn Patterson), for certain equipment and metal fabrication services. Purchases from
TMP were at current market prices.
In 2005 and 2004, the Company paid approximately $273,000 and $39,000, respectively, to Melco
Services (""Melco'') for dirt contracting services and $59,000 and $44,000, respectively, to L&N Transporta-
tion (""L&N'') for water hauling services. Both entities are owned by Lance D. Nelson, brother of Jonathan D.
Nelson, Patterson-UTI's former CFO. Purchases from Melco and L&N were at current market prices.
See Note 2 for information pertaining to fraudulent payments made to or for the beneÑt of Jonathan D.
Nelson, our former CFO.
F-36
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II Ì VALUATION AND QUALIFYING ACCOUNTS
Description
Year Ended December 31, 2005
Deducted from asset accounts:
Beginning
Balance
Charged to
Costs and
Expenses(1)
Deductions(2)
Ending
Balance
(In thousands)
Allowance for doubtful accounts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$1,909
$1,231
$ 941
$2,199
Year Ended December 31, 2004
Deducted from asset accounts:
Allowance for doubtful accounts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$2,133
$ 897
$1,121
$1,909
Year Ended December 31, 2003
Deducted from asset accounts:
Allowance for doubtful accounts ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
$3,144
$ 259
$1,270
$2,133
(1) Net of recoveries.
(2) Uncollectible accounts written oÅ.
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/ CLOYCE A. TALBOTT
Cloyce A. Talbott
Chief Executive OÇcer
Date: March 30, 2006
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 March 30, 2006.
Signature
Title
/s/ MARK S. SIEGEL
Mark S. Siegel
/s/ CLOYCE A. TALBOTT
Cloyce A. Talbott
(Principal Executive OÇcer)
Chairman of the Board
Chief Executive OÇcer and Director
/s/ A. GLENN PATTERSON
President, Chief Operating OÇcer and Director
A. Glenn Patterson
/s/ KENNETH N. BERNS
Kenneth N. Berns
Senior Vice President and Director
/s/
JOHN E. VOLLMER III
John E. Vollmer III
(Principal Financial and Accounting OÇcer)
Senior Vice President Ì Corporate Development,
Chief Financial OÇcer, Secretary and Treasurer
/s/ ROBERT C. GIST
Robert C. Gist
/s/ CURTIS W. HUFF
Curtis W. HuÅ
/s/ TERRY H. HUNT
Terry H. Hunt
/s/ KENNETH R. PEAK
Kenneth R. Peak
/s/ NADINE C. SMITH
Nadine C. Smith
Director
Director
Director
Director
Director
EXHIBIT 31.1
I, Cloyce A. Talbott, certify that,
CERTIFICATIONS
1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the Ñnancial statements, and other Ñnancial information included in this
report, fairly present in all material respects the Ñnancial condition, results of operations and cash Öows of the
registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying oÇcer(s) and I are responsible for establishing and maintaining
disclosure controls and procedures (as deÑned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over Ñnancial reporting (as deÑned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
(b) Designed such internal control over Ñnancial reporting, or caused such internal control over
Ñnancial reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of Ñnancial reporting and the preparation of Ñnancial statements for external purposes in
accordance with generally accepted accounting principles;
(c) Evaluated the eÅectiveness of the registrant's disclosure controls and procedures and presented
in this report our conclusions about the eÅectiveness of the disclosure controls and procedures, as of the
end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over Ñnancial reporting
that occurred during the registrant's most recent Ñscal quarter (the registrant's fourth Ñscal quarter in the
case of an annual report) that has materially aÅected, or is reasonably likely to materially aÅect, the
registrant's internal control over Ñnancial reporting; and
5. The registrant's other certifying oÇcers and I have disclosed, based on our most recent evaluation of
internal control over Ñnancial reporting, to the registrant's auditors and the audit committee of the registrant's
board of directors (or persons performing the equivalent functions):
(a) all signiÑcant deÑciencies and material weaknesses in the design or operation of internal control
over Ñnancial reporting which are reasonably likely to adversely aÅect the registrant's ability to record,
process, summarize and report Ñnancial information; and
(b) any fraud, whether or not material, that involves management or other employees who have a
signiÑcant role in the registrant's internal control over Ñnancial reporting.
Date: March 30, 2006
/s/ CLOYCE A. TALBOTT
Cloyce A. Talbott
Chief Executive OÇcer
EXHIBIT 31.2
I, John E. Vollmer III, certify that:
CERTIFICATIONS
1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the Ñnancial statements, and other Ñnancial information included in this
report, fairly present in all material respects the Ñnancial condition, results of operations and cash Öows of the
registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying oÇcers and I are responsible for establishing and maintaining
disclosure controls and procedures (as deÑned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over Ñnancial reporting (as deÑned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
(b) Designed such internal control over Ñnancial reporting, or caused such internal control over
Ñnancial reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of Ñnancial reporting and the preparation of Ñnancial statements for external purposes in
accordance with generally accepted accounting principles;
(c) Evaluated the eÅectiveness of the registrant's disclosure controls and procedures and presented
in this report our conclusions about the eÅectiveness of the disclosure controls and procedures, as of the
end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over Ñnancial reporting
that occurred during the registrant's most recent Ñscal quarter (the registrant's fourth Ñscal quarter in the
case of an annual report) that has materially aÅected, or is reasonably likely to materially aÅect, the
registrant's internal control over Ñnancial reporting; and
5. The registrant's other certifying oÇcers and I have disclosed, based on our most recent evaluation of
internal control over Ñnancial reporting, to the registrant's auditors and the audit committee of the registrant's
board of directors (or persons performing the equivalent functions):
(a) all signiÑcant deÑciencies and material weaknesses in the design or operation of internal control
over Ñnancial reporting which are reasonably likely to adversely aÅect the registrant's ability to record,
process, summarize and report Ñnancial information; and
(b) any fraud, whether or not material, that involves management or other employees who have a
signiÑcant role in the registrant's internal control over Ñnancial reporting.
/s/
JOHN E. VOLLMER III
John E. Vollmer III
Senior Vice President Ì Corporate Development,
Chief Financial OÇcer, Secretary and Treasurer
Date: March 30, 2006
Corporate Information
Corporate Office
Directors
Corporate Officers
Mark S. Siegel
Chairman
Cloyce A. Talbott
President and
Chief Executive Officer
Kenneth N. Berns
Senior Vice President
John E. Vollmer III
Senior Vice President-
Corporate Development,
Chief Financial Officer,
Secretary and Treasurer
Patterson-UTI Energy, Inc.
P.O. Box 1416
Snyder, Texas 79550
4510 Lamesa Highway
Snyder, Texas 79549
Telephone: (325) 574-6300
Fax: (325) 574-6390
www.patenergy.com
Common Stock
Nasdaq: PTEN
Transfer Agent
Continental Stock
Transfer & Trust Company
17 Battery Place
New York, NY 10004
Toll-Free number:
(800) 509-5586
www.continentalstock.com
Independent Auditor
PricewaterhouseCoopers LLP
Corporate Counsel
Fulbright & Jaworski LLP
Mark S. Siegel
Chairman, Patterson-UTI Energy, Inc.;
President, Remy Investors and
Consultants, Incorporated
Cloyce A. Talbott
President and
Chief Executive Officer,
Patterson-UTI Energy, Inc.
Glenn Patterson
Former President and
Chief Operating Officer,
Patterson-UTI Energy, Inc.
Kenneth N. Berns
Senior Vice President,
Patterson-UTI Energy, Inc.
Robert C. Gist
Attorney at Law
Curtis W. Huff
President and
Chief Executive Officer,
Freebird Investments LLC
Terry H. Hunt
Energy Consultant
and Investor
Kenneth R. Peak
President and
Chief Executive Officer,
Contango Oil & Gas
Nadine C. Smith
Business Consultant
and Investor
Patterson-UTI Energy, Inc.
P.O. Box 1416
Snyder, Texas 79550
4510 Lamesa Highway
Snyder, Texas 79549
Telephone: (325) 574-6300
Fax: (325) 574-6390
www.patenergy.com