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10-K 1 d33317e10vk.htm FORM 10-K e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 2005

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to

Commission File Number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		75-2504748 (I.R.S. Employer Identification No.)


4510 Lamesa Highway, Snyder, Texas (Address of principal executive offices)		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 checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ or No o

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o or No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2005, the last business day of the registrant’s most recently completed second fiscal 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:

Definitive Proxy Statement for the 2006 Annual Meeting of Stockholders (Part III).

TABLE OF CONTENTS


PART I
	Item 1. Business
	Item 3. Legal Proceedings.
	Item 4. Submission of Matters to a Vote of Security Holders.
PART II
	Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities.
	Item 6. Selected Financial Data.
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data.
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
	Item 9A. Controls and Procedures.
	Item 9B. Other Information
PART III
	Item 10. Directors and Executive Officers of the Registrant.
	Item 11. Executive Compensation.
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
	Item 13. Certain Relationships and Related Transactions.
	Item 14. Principal Accountant Fees and Services.
PART IV
	Item 15. Exhibits and Financial Statement Schedule.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
		CONSOLIDATED BALANCE SHEETS
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SIGNATURES
EXHIBIT INDEX
Subsidiaries
Consent of Independent Registered Public Accounting Firm
Certification of Chief Executive Officer
Certification of Chief Financial Officer
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906

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.

PART I


Item 1.	*Business*

Available Information

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 filed 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 file 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 fleet 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 fluids, completion fluids 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 fluids 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.

Embezzlement and Restatements

On November 3, 2005, we announced the resignation of our Chief Financial Officer (“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 financial 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 reflect losses incurred as a result of payments made to or for the benefit of Nelson that had been recognized in our accounting records and previously issued financial statements as payments for assets and services that we did not receive. Previously issued financial statements have also been restated for the effects 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 financial statements, and on March 17, 2006, we filed our amended Annual Report on Form 10-K/A and on March 27, 2006, we filed 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 benefit 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 fictitious property and equipment approval forms with forged signatures.

The total amount embezzled was approximately $77.5 million in cash, excluding any tax effects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):


From 1998 to December 31, 2004			$	58,961
From January 1, 2005 to September 30, 2005(1)				12,193

	Total through September 30, 2005			71,154
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1)				6,350

		Total embezzlement	$	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.

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 effects of the embezzlement on our financial position follow (in thousands):


	December 31,

Decrease in amounts previously reported	2004			2003

Assets(1)	$	(56,133	)	$	(38,540	)
Liabilities(2)		(20,848	)		(15,044	)

Retained earnings and stockholders’ equity	$	(35,285	)	$	(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.

The financial statements and related financial and statistical data contained in this Report have been restated to provide for, net of related tax effects, (1) the effects of losses incurred as a result of the embezzlement and (2) the effects of the correction of other errors that are immaterial both individually and in the aggregate.

Industry Segments

Our revenues, operating profits and identifiable assets are primarily attributable to four industry segments:


	•	contract drilling,

	•	pressure pumping services,

	•	drilling and completion fluids services, and

	•	oil and natural gas development, exploration, acquisition and production.

With respect to these four segments:


	•	the contract drilling segment had operating profits in 2005, 2004 and 2003,

	•	the pressure pumping segment had operating profits in 2005, 2004 and 2003,

	•	the drilling and completion fluids segment had operating profits in 2005 and 2004 and an operating loss in 2003, and

	•	the oil and natural gas segment had operating profits 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 financial information pertaining to these industry segments.

Contract Drilling Operations

General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 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,


	•	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 fluid,

	•	blowout preventers,

	•	drill string (pipe), and

	•	other related equipment.

Over time, components on a drilling rig are replaced or rebuilt. We spend significant 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 fiscal 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

	•	qualified personnel,

some of which have been in short supply from time to time.

Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. 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 beneficial 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

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 specified conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the agreed depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor assumes certain risks associated with loss of the well from fire, 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 specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed scope of the work has been completed which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. However, given the increased exposure we have under a turnkey contract, profits can be significantly 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 different 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.

Revenues by Contract Type — Information regarding our contract drilling activity for the last three years follows:


	Years Ended December 31,

Type of Revenues	2005			2004			2003

Daywork		98	%		88	%		83	%
Footage		1			6			7
Turnkey		1			6			10

Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:


	Years Ended December 31,

	2005			2004			2003

Average rigs owned		397			359			336
Average rigs operating(1)		276			211			188
Average rig utilization rate		69	%		59	%		56	%
Number of rigs operated		307			259			226
Number of wells drilled		4,594			3,534			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 — Certain drilling rig information as of December 31, 2005 follows:


Depth Rating (Ft.)		Mechanical		Electric		Total

4,000 to 9,999			79		—		79
10,000 to 11,999			76		2		78
12,000 to 14,999			139		8		147
15,000 to 30,000			67		32		99

	Totals		361		42		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 efficiency of our contract drilling operations particularly in periods of high drilling rig utilization.

Most repair and overhaul work to our drilling rig equipment is performed at our yard facilities located in Texas, New Mexico, Oklahoma, Utah and Western Canada.

Pressure Pumping Operations

General — We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Most wells drilled in the Appalachian Basin require some form of fracturing or other stimulation to enhance the flow of oil and natural gas by pumping fluids under pressure into the well bore. 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 — Our pressure pumping equipment at December 31, 2005 follows:


	•	30 cement pumper trucks,

	•	33 fracturing pumper trucks,

	•	30 nitrogen pumper trucks,


	•	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 — We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. We serve our offshore 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 — Drilling fluid 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 effectively to optimize drilling operations.

Completion Fluids — After a well is drilled, the well casing is set and cemented into place. At that point, the drilling fluid services are complete and the drilling fluids are circulated out of the well and replaced with completion fluids. Completion fluids, also known as clear brine fluids, are solids-free, clear salt solutions that have high specific gravities. Combined with a range of specialty chemicals, these fluids are used to control bottom-hole pressures and to meet specific corrosion, inhibition, viscosity and fluid loss requirements.

Raw Materials — Our drilling and completion fluids 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 — 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 fluids.

Other Equipment — We own 24 trucks and 79 trailers and lease another 24 trucks which are used to transport drilling and completion fluids and related equipment.

Oil and Natural Gas Operations

General — 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 significantly 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.

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 — 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 — The drilling and completion fluids 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 fluids 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 — 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 financial 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, oilfield waste, other waste materials and acids,

	•	use of underground storage tanks, and

	•	use of underground injection wells.

To date, applicable environmental laws and regulations have not required the expenditure of significant 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 affected 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 affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling and production. They could have an adverse effect on our operations. 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

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 definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.

The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern:


	•	the prevention of discharges, including oil and produced water spills, and

	•	liability for drainage into waters.

The Oil Pollution Act 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 fluids business. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.

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 definition 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,


	•	fires, and

	•	explosions.

These hazards could cause:


	•	personal injury or death,

	•	suspension of drilling operations, or

	•	serious damage or destruction of the equipment involved and, in addition to environmental damage, could cause substantial damage to producing formations and surrounding areas.

Damage to the environment, including property contamination in the form of either soil or ground water contamination, could also result from our operations, particularly through:


	•	oil or produced water spillage,

	•	natural gas leaks, and

	•	fires.

In addition, we could become subject to liability for reservoir damages. The occurrence of a significant event, including pollution or environmental damages, could materially affect our operations and financial 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 sufficient to protect us against liability for all consequences of:


	•	personal injury,

	•	well disasters,

	•	extensive fire damage,

	•	damage to the environment, or

	•	other hazards.

We also carry insurance 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 difficulties that may be encountered in renewing such insurance at reasonable rates, no assurance can be given that:


	•	we will be able to maintain the type and amount of coverage that we believe to be adequate at reasonable rates, or

	•	any particular types of coverage will be available.

In addition to insurance coverage, we also attempt to obtain indemnification from our customers for certain risks. These indemnity agreements typically require our customers to hold us harmless in the event of loss of production or reservoir damage. These contractual indemnifications may not be supported by adequate insurance maintained by the customer.

Employees

We employed approximately 8,600 full-time persons (450 office personnel and 8,150 field personnel) at December 31, 2005. The number of field employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be satisfactory. None of our employees are represented by a union.

Seasonality

Seasonality does not significantly affect our overall operations. However, our 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 filings 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, financing of operations, sources and sufficiency of funds and impact of inflation. 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 identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ 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 differences 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.

Taking this into account, the following are identified 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 Affected Our Operations.*

Our revenue, profitability 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 affected by:


	•	market supply and demand,

	•	international military, political and economic conditions, and

	•	the ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets.

All of these factors are beyond our control. Natural gas prices fell from an average of $6.23 per Mcf in the first 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 affect our financial condition and operations and ability to access sources of capital. A significant 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 Affects Our Profit 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 difficulty sustaining profit margins during the downturn periods.

In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:


	•	movement of drilling rigs from region to region,

	•	reactivation of land-based drilling rigs, or

	•	construction of new drilling rigs.

We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.


	*Shortages of Drill Pipe, Replacement Parts and Other Related Rig Equipment Adversely Affects Our Operating Results.*

During periods of increased demand for drilling services, the industry has experienced shortages of drill pipe, replacement parts and other related rig equipment. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. 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.


	*The Various Business Segments in Which We Operate Are Highly Competitive with Excess Capacity which may Adversely Affect 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 fluids 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 fluids 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 Affect Our Operating Results.*

During periods of increasing demand for contract drilling services, the industry experiences shortages of qualified drilling rig personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs is adversely affected which negatively impacts both our operations and profitability. Operationally, it is more difficult to hire qualified personnel which adversely affects our ability to mobilize inactive rigs 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 fleet over the past several years through mergers and acquisitions. The land drilling industry has experienced significant 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 sufficient capital resources to complete additional acquisitions,

	•	successfully integrate acquired operations and assets,

	•	effectively 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 financial condition, results of operations, business or prospects in any material manner as a result of any completed acquisition.

We may incur substantial indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with any such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity would be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources.


	*The Nature of our Business Operations Presents Inherent Risks of Loss that, if not Insured or Indemnified Against, Could Adversely Affect Our Operating Results.*

Our operations are subject to many hazards inherent in the contract drilling, pressure pumping, and drilling and completion fluids businesses, which in turn could cause personal injury or death, work stoppage, or serious damage to our equipment. Our operations could also cause environmental and reservoir damages. We maintain insurance coverage and have indemnification agreements with many of our customers. However, there is no assurance that such insurance or indemnification agreements would adequately protect us against liability or losses from all consequences of 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 significantly 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 Affect 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 field 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 significant risks. Under turnkey drilling contracts, we contract to drill a well to a certain depth under specified conditions at a fixed price. Under footage contracts, we contract to drill a well to a certain depth under specified conditions at a fixed 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 fire, machinery breakdowns and abnormal drilling conditions. Accordingly, if severe drilling problems are encountered in drilling wells under such contracts, we could suffer substantial losses.


	*Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price.*

We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law 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 find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.


Item 1B.	*Unresolved Staff Comments.*

None.


Item 2.	*Properties*

Our corporate headquarters are located in Snyder, Texas. We also have a number of offices, 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:


	•	office buildings with approximately 37,000 square feet of office 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 fleet,

	•	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 offices, 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 — Our drilling services are supported by several administrative offices and yard facilities located throughout our areas of operations including:


	•	Texas,

	•	New Mexico,

	•	Oklahoma,

	•	Colorado,

	•	Utah,

	•	Wyoming, and

	•	Western Canada.

Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations including:


	•	Pennsylvania,

	•	Ohio,

	•	West Virginia,

	•	Kentucky,

	•	Tennessee, and

	•	Wyoming.

Drilling and Completion Fluids — Our drilling and completion fluids services are supported by several administrative offices and stockpoint facilities located throughout our areas of operations including:


	•	Texas,

	•	Louisiana,

	•	New Mexico, and

	•	Oklahoma.

Oil and Natural Gas — Our oil and natural gas operations are supported by administrative and field offices 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 filed in Texas state court in Scurry County, Texas, against our directors, alleging that the directors breached their fiduciary duties to us as a result of alleged failure to timely discover the embezzlement by Nelson, and against our principal accounting firm, PricewaterhouseCoopers LLP, alleging that such firm 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 effect on our financial condition.


Item 4.	*Submission of Matters to a Vote of Security Holders.*

None.

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 reflect the two-for-one stock split on June 30, 2004:


	High		Low

2005:
First quarter	$	26.66	$	17.15
Second quarter		29.33		22.38
Third quarter		36.79		27.79
Fourth quarter		36.73		28.45
2004:
First quarter	$	19.20	$	15.75
Second quarter		19.56		14.52
Third quarter		19.88		15.69
Fourth quarter		20.45		17.85


*(b)*	*Holders*

As of March 10, 2006, there were approximately 2,174 holders of record and approximately 92,452 beneficial 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, financial 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.

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.


					Total number		Maximum number
					of shares (or		(or approximate dollar
					units) purchased		value) of shares
	Total number				as part of publicly		(or units) that may
	of shares		Average price		announced plans		yet be purchased under
Period covered	purchased(1)		paid per share		or programs(2)		the plans or programs(2)

October 1–31, 2005		—	$	—		—	$	28,518,216
November 1–30, 2005		355,000	$	34.23		355,000	$	16,364,873
December 1–31, 2005		—	$	—		—	$	16,364,873

Total		355,000	$	34.23		355,000	$	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, officers and directors as of December 31, 2005 follows:

Equity Compensation Plan Information

Number of

Securities

Securities to

Weighted-

Remaining Available

be Issued upon

Average Exercise

for Future Issuance

Exercise of

Price of

under Equity

Outstanding

Compensation Plans

Options,

(Excluding

Warrants and

Securities Reflected

Plan Category

Rights

in Column(a))

(a)

(b)

(c)

Equity compensation plans approved by security holders

5,449,739

15.11

5,464,217

(1)

Equity compensation plans not approved by security holders(2)

888,304

9.87

—

Total

6,338,043

14.37

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, officers and directors, which are subject to certain vesting and forfeiture provisions. All options are granted with an exercise price equal to or greater than the fair market value of the common stock at the time of grant. The vesting schedule and term are set by the Compensation Committee of the Board of Directors. All securities remaining available for future issuance under equity compensation plans approved by security holders in column (c) are available under this plan.

(2)

The Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (the “2001 Plan”) was approved by the Board of Directors in July 2001. In connection with the approval of the 2005 Plan, the Board of Directors approved a resolution that no further options, restricted stock or other awards would be granted under any equity compensation plan, other than the 2005 Plan. The terms of the 2001 Plan provided for grants of stock options, stock appreciation rights, shares of restricted stock and performance awards to eligible employees other than officers and directors. No Incentive Stock Options could be awarded under the 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.


Item 6.	*Selected Financial Data.*

Our selected consolidated financial data as of December 31, 2005, 2004, 2003, 2002 and 2001, and for each of the five 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 financial data presented below was previously reported as restated to provide for (i) the retroactive effect 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 financial data presented below has been further restated to provide for, net of related tax effects, (i) the effects of losses incurred as a result of the embezzlement and (ii) the effects 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 financial data below. Certain reclassifications have been made to the historical financial data to conform with the 2004 presentation.


			Years Ended December 31,

					Restated (See Note 2)

			2005		2004			2003			2002			2001

			(In thousands)
Income Statement Data:
Operating revenues:
	Contract drilling		$	1,485,684	$	809,691		$	639,694		$	410,295		$	839,931
	Pressure pumping			93,144		66,654			46,083			32,996			39,600
	Drilling and completion fluids			122,011		90,557			69,230			69,943			94,456
	Oil and natural gas			39,616		33,867			21,163			14,723			15,988

		Total		1,740,455		1,000,769			776,170			527,957			989,975

Operating costs and expenses:
	Contract drilling			776,313		556,869			475,224			318,201			487,343
	Pressure pumping			54,956		37,561			26,184			19,802			21,146
	Drilling and completion fluids			98,530		76,503			61,424			60,762			80,034
	Oil and natural gas			9,566		7,978			4,808			3,956			5,190
	Depreciation, depletion, amortization and impairment			156,393		122,800			100,834			92,778			86,035
	Selling, general and administrative			39,110		31,983			27,685			26,116			28,462
	Bad debt expense			1,231		897			259			320			2,045
	Merger costs			—		—			—			—			5,943
	Restructuring and other charges			—		—			—			—			7,202
	Embezzled funds and related expenses			20,043		19,122			17,849			8,574			7,674
	Other (including gain or loss on sale of assets)			3,017		(1,411	)		(4,379	)		4,340			(820	)

		Total		1,159,159		852,302			709,888			534,849			730,254

Operating income (loss)				581,296		148,467			66,282			(6,892	)		259,721
Other income (expense)				3,463		680			2,694			803			(677	)

Income (loss) before income taxes and cumulative effect of change in accounting principle				584,759		149,147			68,976			(6,089	)		259,044
Income tax expense (benefit)				212,019		54,801			25,320			(1,949	)		99,472

Income (loss) before cumulative effect of change in accounting principle				372,740		94,346			43,656			(4,140	)		159,572
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287				—		—			(469	)		—			—

Net income (loss)			$	372,740	$	94,346		$	43,187		$	(4,140	)	$	159,572


			Years Ended December 31,

					Restated (See Note 2)

			2005		2004		2003		2002		2001

			(In thousands, except per share amounts)
Net income (loss) per common share:
	Basic:
		Income (loss) before cumulative effect of change in accounting principle	$	2.19	$	0.57	$	0.27	$	(0.03)	$	1.04

		Cumulative effect of change in accounting principle	$	—	$	—	$	—	$	—	$	—

		Net income (loss)	$	2.19	$	0.57	$	0.27	$	(0.03)	$	1.04

	Diluted:
		Income (loss) before cumulative effect of change in accounting principle	$	2.15	$	0.56	$	0.27	$	(0.03)	$	1.01

		Cumulative effect of change in accounting principle	$	—	$	—	$	—	$	—	$	—

		Net income (loss)	$	2.15	$	0.56	$	0.26	$	(0.03)	$	1.01

Cash dividends per common share			$	0.16	$	0.06	$	—	$	—	$	—

Weighted average number of common shares outstanding:
	Basic			170,426		166,258		161,272		157,410		152,814

	Diluted			173,767		169,211		164,572		157,410		158,394

Balance Sheet Data:
Total assets			$	1,795,781	$	1,256,785	$	1,039,521	$	919,374	$	856,855
Stockholders’ equity				1,367,011		961,501		789,814		724,248		680,341
Working capital				382,448		235,480		198,399		166,885		109,566


(1)	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.


	The total amount embezzled was approximately $77.5 million in cash, excluding any tax effects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):


From 1998 to December 31, 2004			$	58,961
From January 1, 2005 to September 30, 2005(1)				12,193

	Total through September 30, 2005			71,154
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1)				6,350

		Total embezzlement	$	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 effects 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	$	171,214		$	87,190		$	3,398		$	267,172
	Adjustment for effects of embezzlement		(18,637	)		(17,375	)		(8,249	)		(7,461	)
	Other adjustments		(4,110	)		(3,533	)		(2,041	)		10

	As restated	$	148,467		$	66,282		$	(6,892	)	$	259,721


	The effects 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			$	108,733		$	56,419		$	2,374		$	164,162

		Adjustments:
			Embezzled funds expense			(19,122	)		(17,849	)		(8,574	)		(7,674	)
			Embezzlement amounts previously expensed as depreciation and selling, general and administrative			485			474			325			213

			Embezzlement expense, net of amounts previously expensed			(18,637	)		(17,375	)		(8,249	)		(7,461	)
			Other adjustments			(4,110	)		(3,533	)		(2,041	)		10
			Tax benefits			8,360			7,676			3,776			2,861

				Net adjustment		(14,387	)		(13,232	)		(6,514	)		(4,590	)

		Net income (loss) as restated			$	94,346		$	43,187		$	(4,140	)	$	159,572

Net income (loss) per common share:
	Basic:
		As previously reported			$	0.65		$	0.35		$	0.02		$	1.07
		Adjustment for effects of embezzlement			$	(0.07	)	$	(0.07	)	$	(0.03	)	$	(0.03	)
		Other adjustments			$	(0.02	)	$	(0.01	)	$	(0.01	)	$	—
		As restated			$	0.57		$	0.27		$	(0.03	)	$	1.04
	Diluted:
		As previously reported			$	0.64		$	0.34		$	0.01		$	1.04
		Adjustment for effects of embezzlement			$	(0.07	)	$	(0.07	)	$	(0.03	)	$	(0.03	)
		Other adjustments			$	(0.02	)	$	(0.01	)	$	(0.01	)	$	—
		As restated			$	0.56		$	0.26		$	(0.03	)	$	1.01


	The effects of the restatement due to the embezzlement and other adjustments on selected balance sheet data as previously reported for 2004 and prior years follow:


			December 31,

			2004			2003			2002			2001

			(In thousands)
Total assets:
	As previously reported		$	1,322,911		$	1,084,114		$	942,823		$	869,642
	Adjustment for effects of embezzlement:
		Property and equipment and other		(56,133	)		(37,496	)		(20,121	)		(11,872	)
		Income taxes receivable		—			(1,044	)		(807	)		(531	)

				(56,133	)		(38,540	)		(20,928	)		(12,403	)
	Other adjustments:
		Property and equipment and other		(9,993	)		(5,883	)		(2,350	)		(309	)
		Income taxes receivable		—			(170	)		(171	)		(75	)

				(9,993	)		(6,053	)		(2,521	)		(384	)
	As restated		$	1,256,785		$	1,039,521		$	919,374		$	856,855

Stockholders’ equity:
	As previously reported		$	1,007,539		$	819,749		$	737,731		$	687,142
	Adjustment for effects of embezzlement			(35,285	)		(23,496	)		(12,499	)		(7,373	)
	Other adjustments			(10,753	)		(6,439	)		(984	)		572

	As restated		$	961,501		$	789,814		$	724,248		$	680,341

Working capital:
	As previously reported		$	236,957		$	199,613		$	167,863		$	110,172
	Adjustment for effects of embezzlement			(1,311	)		(1,044	)		(807	)		(531	)
	Other adjustments			(166	)		(170	)		(171	)		(75	)

	As restated		$	235,480		$	198,399		$	166,885		$	109,566


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 financial statements and related financial 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, filed on March 17, 2006. The determination to restate these financial statements and other information was made as a result of management’s identification 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 — 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 fluid 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	$	1,485,684	86	%	$	809,691	81	%	$	639,694	82	%
Pressure pumping		93,144	5			66,654	7			46,083	6
Drilling and completion fluids		122,011	7			90,557	9			69,230	9
Oil and natural gas		39,616	2			33,867	3			21,163	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 fluids 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 fleet 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 significant transaction occurred in May 2001 when we merged with UTI Energy Corp. in a merger of equals which basically doubled our drilling fleet and added the pressure pumping services business. Growth by acquisition has been a corporate strategy intended to expand both revenues and profits.

The profitability 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, profitability and cash flows 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.

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 — 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.

The total amount embezzled was approximately $77.5 million in cash, excluding any tax effects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):


From 1998 to December 31, 2004			$	58,961
From January 1, 2005 to September 30, 2005(1)				12,193

	Total through September 30, 2005			71,154
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1)				6,350

		Total embezzlement	$	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 — We maintain letters of credit in the aggregate amount of approximately $56 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These

letters of credit expire at various times during each calendar year. 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 financial 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 filed in Texas state court in Scurry County, Texas, against our directors, alleging that the directors breached their fiduciary 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 — 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 — 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 fluids, completion fluids 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 fluids 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 difficulty sustaining profit margins during the downturn periods.

In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect 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.

Critical Accounting Policies

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, oil and natural gas properties, goodwill, revenue recognition and the use of estimates.

Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our 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 fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends, we estimate future cash flows 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 flows, on an undiscounted basis, are less than the asset’s net book value. Impairment charges are recorded based on discounted cash flows. There were no impairment charges to property and equipment during the years 2005, 2004 or 2003.

Oil and natural gas properties — Oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. 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 classification. If the reserve classification 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 field. 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 field and undiscounted cash flow estimates are provided by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between its net book value and discounted cash flow. Unproved oil and natural gas properties are reviewed quarterly to 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 financial statements.

Goodwill — Goodwill is considered to have an indefinite 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.

Revenue recognition — Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed contract method of accounting, 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 — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

Key estimates used by management include:


	•	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 affiliated 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, affiliated 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 efficient for us to sell the working interests to these affiliated 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 affiliated persons was the same price at which working interests were sold to unaffiliated persons.

Production revenues and joint interest costs of each of the affiliated persons during 2005 for all wells operated by us in which the affiliated persons have working interests are presented in the table below. These amounts do not necessarily represent their profits 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 affiliated persons of approximately $1.5 million and $1.2 million

and a receivable from the affiliated persons of approximately $1.2 million and $856,000 at December 31, 2005 and 2004, respectively.


			Year Ended
			December 31, 2005

					Joint
			Production		Interest
Name			Revenues(1)		Costs(2)

Cloyce A. Talbott			$	195,491	$	49,668
Anita Talbott(3)				88,824		21,389
Jana Talbott, Executrix to the Estate of Steve Talbott(3)				19,373		2,871
Stan Talbott(3)				7,639		3,163
John Evan Talbott Trust(3)				3,725		987
Lisa Beck and Stacy Talbott(3)				1,158,657		492,839
SSI Oil & Gas, Inc.(4)				210,825		97,152
IDC Enterprises, Ltd.(5)				13,432,098		8,460,393

	Subtotal			15,116,632		9,128,462

A. Glenn Patterson				122,348		29,075
Robert Patterson(6)				7,719		4,396
Thomas M. Patterson(6)				7,719		4,396

	Subtotal			137,786		37,867

Jonathan D. Nelson, former Chief Financial Officer				290,506		381,506

		Total	$	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 beneficially 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 benefit of Jonathan D. Nelson, our former CFO.

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 flow 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 fluids 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 fleet 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 five 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 five-year, $200 million unsecured revolving line of credit (“LOC”). Interest is to be paid on outstanding LOC balances at a floating 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 reflect 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 sufficient to meet our capital needs. From time to time, acquisition opportunities are

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 financing or equity financing. 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:


	Years Ended December 31,

				Restated
				(See Note 2)
Contract Drilling	2005			2004			% Change

	(Dollars in thousands)
Revenues	$	1,485,684		$	809,691			83.5	%
Direct operating costs	$	776,313		$	556,869			39.4	%
Selling, general and administrative	$	5,069		$	4,417			14.8	%
Depreciation	$	131,740		$	101,779			29.4	%
Operating income	$	572,562		$	146,626			290.5	%
Operating days		100,591			77,355			30.0	%
Average revenue per operating day	$	14.77		$	10.47			41.1	%
Average direct operating costs per operating day	$	7.72		$	7.20			7.2	%
Number of owned rigs at end of period		403			361			11.6	%
Average number of rigs owned during period		397			359			10.6	%
Average rigs operating		276			211			30.8	%
Rig utilization percentage		69	%		59	%		16.9	%
Capital expenditures	$	329,073		$	140,945			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 fiscal quarters in 2005 and 2004 follow:


	1st		2nd		3rd		4th
	Quarter		Quarter		Quarter		Quarter

2005:
Average natural gas price	$	6.62	$	7.14	$	9.82	$	12.64
Average rigs operating		263		265		283		292
2004:
Average natural gas price	$	5.64	$	6.13	$	5.62	$	6.42
Average rigs operating		197		203		216		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. Significant 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, fluid circulating systems, rig hoisting systems and safety

enhancement equipment. Increased depreciation expense in 2005 was due to acquisitions and capital expenditures in 2004 and 2005.


	Years Ended December 31,

Pressure Pumping	2005		2004		% Change

	(Dollars in thousands)
Revenues	$	93,144	$	66,654		39.7	%
Direct operating costs	$	54,956	$	37,561		46.3	%
Selling, general and administrative	$	9,430	$	7,234		30.4	%
Depreciation	$	7,094	$	5,112		38.8	%
Operating income	$	21,664	$	16,747		29.4	%
Total jobs		9,615		7,444		29.2	%
Average revenue per job	$	9.69	$	8.95		8.3	%
Average direct operating costs per job	$	5.72	$	5.05		13.3	%
Capital expenditures	$	25,508	$	17,705		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 modifications and upgrades to existing equipment and facilities.


	Years Ended December 31,

			Restated
			(See Note 2)
Drilling and Completion Fluids	2005		2004		% Change

	(Dollars in thousands)
Revenues	$	122,011	$	90,557		34.7	%
Direct operating costs	$	98,530	$	76,503		28.8	%
Selling, general and administrative	$	8,912	$	7,696		15.8	%
Depreciation	$	2,368	$	2,156		9.8	%
Other operating	$	254	$	—		N/A	%
Operating income	$	11,947	$	4,202		184.3	%
Total jobs		1,980		2,205		(10.2	)%
Average revenue per job	$	61.62	$	41.07		50.0	%
Average direct operating costs per job	$	49.76	$	34.70		43.4	%
Capital expenditures	$	3,042	$	1,488		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 offshore jobs. Selling, general and administrative expense increased primarily due to increased incentive compensation resulting from higher profitability levels. Other expense from operations

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.


	Years Ended December 31,

Oil and Natural Gas Production and Exploration	2005		2004		% Change

	(Dollars in thousands)
Revenues	$	39,616	$	33,867		17.0	%
Direct operating costs	$	9,566	$	7,978		19.9	%
Selling, general and administrative	$	2,189	$	1,816		20.5	%
Depreciation, depletion and impairment	$	14,456	$	13,309		8.6	%
Operating income	$	13,405	$	10,764		24.5	%
Capital expenditures	$	17,163	$	14,451		18.8	%
Average net daily oil production (Bbls)		860		1,071		(19.7	)%
Average net daily gas production (Mcf)		7,016		7,429		(5.6	)%
Average oil sales price (per Bbl)	$	54.30	$	39.12		38.8	%
Average gas sales price (per Mcf)	$	7.64	$	5.81		31.5	%

Revenues increased due to increased market prices for oil and natural gas. Direct operating costs increased as a result of higher oilfield 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 offset 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.


	Years Ended December 31,

			Restated
			(See Note 2)
Corporate and Other	2005		2004			% Change

	(Dollars in thousands)
Selling, general and administrative	$	13,510	$	10,820			24.9	%
Bad debt expense	$	1,231	$	897			37.2	%
Depreciation	$	735	$	444			65.5	%
Other operating (including gain or loss on sale of assets)	$	2,763	$	(1,411	)		N/A	%
Embezzled funds and related expenses	$	20,043	$	19,122			4.8	%
Interest income	$	3,551	$	1,140			211.5	%
Interest expense	$	516	$	695			(25.8	)%
Other income	$	428	$	235			82.1	%
Capital expenditures	$	5,308	$	—			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 benefit 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 financial failure of a workers’ compensation insurance carrier used previously by the Company.


	*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:


	Restated (See Note 2)

	Years Ended December 31,

Contract Drilling	2004			2003			% Change

	(Dollars in thousands)
Revenues	$	809,691		$	639,694			26.6	%
Direct operating costs	$	556,869		$	475,224			17.2	%
Selling, general and administrative	$	4,417		$	4,401			0.4	%
Depreciation	$	101,779		$	87,255			16.6	%
Operating income	$	146,626		$	72,814			101.4	%
Operating days		77,355			68,798			12.4	%
Average revenue per operating day	$	10.47		$	9.30			12.6	%
Average direct operating costs per operating day	$	7.20		$	6.91			4.2	%
Number of owned rigs at end of period		361			343			5.2	%
Average number of rigs owned during period		359			336			6.8	%
Average rigs operating		211			188			12.2	%
Rig utilization percentage		59	%		56	%		5.4	%
Capital expenditures	$	140,945		$	77,350			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 fiscal quarters in 2004 and 2003 follow:


	1st		2nd		3rd		4th
	Quarter		Quarter		Quarter		Quarter

2004:
Average natural gas price	$	5.64	$	6.13	$	5.62	$	6.42
Average rigs operating		197		203		216		229
2003:
Average natural gas price	$	5.91	$	5.70	$	4.88	$	5.29
Average rigs operating		176		195		192		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. Significant 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, fluid circulating systems, rig hoisting systems and safety enhancement

equipment. Increased depreciation expense in 2004 was due primarily to capital expenditures in 2003 and 2004, as well as acquisitions.


	Years Ended December 31,

Pressure Pumping	2004		2003		% Change

	(Dollars in thousands)
Revenues	$	66,654	$	46,083		44.6	%
Direct operating costs	$	37,561	$	26,184		43.5	%
Selling, general and administrative	$	7,234	$	5,683		27.3	%
Depreciation	$	5,112	$	3,774		35.5	%
Operating income	$	16,747	$	10,442		60.4	%
Total jobs		7,444		5,667		31.4	%
Average revenue per job	$	8.95	$	8.13		10.1	%
Average direct operating costs per job	$	5.05	$	4.62		9.3	%
Capital expenditures	$	17,705	$	10,524		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 modifications and upgrades to existing equipment and facilities.


	Years Ended December 31,

	Restated (See Note 2)

Drilling and Completion Fluids	2004		2003			% Change

	(Dollars in thousands)
Revenues	$	90,557	$	69,230			30.8	%
Direct operating costs	$	76,503	$	61,424			24.5	%
Selling, general and administrative	$	7,696	$	7,447			3.3	%
Depreciation	$	2,156	$	2,279			(5.4	)%
Operating income (loss)	$	4,202	$	(1,920	)		N/A	%
Total jobs		2,205		1,931			14.2	%
Average revenue per job	$	41.07	$	35.85			14.6	%
Average direct operating costs per job	$	34.70	$	31.81			9.1	%
Capital expenditures	$	1,488	$	912			63.2	%

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

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.


	Years Ended December 31,

Oil and Natural Gas Production and Exploration	2004		2003		% Change

	(Dollars in thousands)
Revenues	$	33,867	$	21,163		60.0	%
Direct operating costs	$	7,978	$	4,808		65.9	%
Selling, general and administrative	$	1,816	$	1,489		22.0	%
Depreciation, depletion and impairment	$	13,309	$	7,082		87.9	%
Operating income	$	10,764	$	7,784		38.3	%
Capital expenditures	$	14,451	$	10,015		44.3	%
Average net daily oil production (Bbls)		1,071		788		35.9	%
Average net daily gas production (Mcf)		7,429		5,656		31.3	%
Average oil sales price (per Bbl)	$	39.12	$	30.54		28.1	%
Average gas sales price (per Mcf)	$	5.81	$	4.97		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.


	Years Ended December 31,

	Restated (See Note 2)

Corporate and Other	2004			2003			% Change

	(Dollars in thousands)
Selling, general and administrative	$	10,820		$	8,665			24.9	%
Bad debt expense	$	897		$	259			246.3	%
Depreciation	$	444		$	444			—	%
Other operating (including gain or loss on sale of assets)	$	(1,411	)	$	(4,379	)		67.8	%
Embezzled funds expense	$	19,122		$	17,849			7.1	%
Interest income	$	1,140		$	1,116			2.2	%
Interest expense	$	695		$	292			138.0	%
Other income	$	235		$	1,870			(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 benefit 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.

Income Taxes


	Years Ended December 31,

				Restated (See Note 2)

	2005			2004			2003

	(Dollars in thousands)
Income before income tax	$	584,759		$	149,147		$	68,976
Income tax expense		212,019			54,801			25,320
Effective tax rate		36.3	%		36.7	%		36.7	%

The significance of the impact of the permanent differences to our effective 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 effective 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 qualified production activities income or taxable income. Our effective 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 differences was not significant 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 — $1 million, 2011 — $2 million, 2018 — $4 million and 2019 — $4 million. The alternative minimum tax credit may be carried forward indefinitely.

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 differences 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 differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We 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, profitability 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 affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC, to set and maintain production and price targets. All of these factors are beyond our control. Natural gas prices fell from an average of $6.23 per Mcf in the first 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 affect our financial condition and operations and ability to access sources of capital. A significant 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.

Impact of Inflation

We believe that inflation will not have a significant near-term impact on our financial position.

Recently-Issued Accounting Standards

The Financial Accounting standards Board (“FASB”) issued Staff Position FIN 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”), an interpretation of FASB Statement No. 143, in March 2005. The statement clarifies 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 financial 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 first 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 first 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 Modified 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 financial position. Adoption is not expected to have a material effect on our financial position or results of operations.

The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs — an amend of ARB No. 43, Chapter 4 (“SFAS 151”). SFAS 151 is effective, and will be adopted, for inventory costs incurred during fiscal 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 effect on our financial position or results of operations.

The FASB issued Statement of Financial Accounting Standard No. 153, Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29 (“SFAS 153”). FAS 153 is effective, and will be adopted, for nonmonetary asset exchanges occurring in fiscal 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 flows of the entity are expected to change significantly as a result of the exchange. Adoption is not expected to have a material effect on our financial position or results of operations.

The FASB issued Statement of Financial Accounting standards No. 154, Accounting changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 145”). SFAS 154 is effective, and will be adopted for accounting changes made in fiscal 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 effects of the change. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.


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 floating rate of the interest charged on that balance. The revolving credit facility calls for periodic interest payments at a floating 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 fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars.


Item 8.	*Financial Statements and Supplementary Data.*

Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference.


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.*

None.


Item 9A.	*Controls and Procedures.*

Background to the Fraud and Restatement

In November 2005, the Company discovered that its former Chief Financial Officer, Jonathan D. Nelson (“Nelson”), had fraudulently diverted approximately $78 million in Company funds for his own benefit. 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 benefit 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 reflecting 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 benefit 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 Officer 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 benefit 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

the wired funds were to be used to pay off 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 finance 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 confirmed 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 financial and business information within the organization between senior management (other than Nelson) and those employees engaged in the Company’s financial reporting and accounting functions (other than Nelson). Nelson also discouraged communication between employees involved in financial 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 flows about financial 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 financial 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 financial 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 financial statements for the years ended December 31, 2004, 2003 and 2002. The Company also restated its previously reported consolidated financial statements for the first three quarters of 2005 and all quarters in 2004 and 2003. The Company filed 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 financial 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 Officer (CEO) and current Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the 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 file 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 filing 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 effective as of December 31, 2004. Subsequent to that evaluation, our CEO and current CFO concluded that our disclosure controls and procedures were not effective 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 filed March 17, 2006. As described below under “Management’s Report on Internal Control Over Financial Reporting,” the Company continues

to report material weaknesses in internal control over financial 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 effective at a reasonable level of assurance. Based upon the substantial work performed during the restatement process, management has concluded that the Company’s consolidated financial 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 financial reporting as such term is defined in Exchange Act Rule 13a-15(f). Our management, including our CEO and current CFO, conducted an evaluation of the effectiveness of our internal control over financial 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 financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Our current management identified the following material weaknesses in our internal control over financial reporting as of December 31, 2005:

1. Control environment. We did not maintain an effective control environment based on the criteria established in the COSO framework. Specifically, 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, financial statements and documents together with forged approval signatures. This lack of an effective control environment allowed our former CFO to take inappropriate actions that resulted in certain transactions not being properly reflected in our consolidated financial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the first 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 effective control environment allowed our lines of communication among, and our monitoring of, our operations and accounting personnel, including our former CFO, to not be effective 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 benefit, specifically 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 benefits 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.

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 fictitious property and equipment approval forms with forged signatures. These actions had the effect 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 financial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the first three quarters of 2005. Additionally, this control environment material weakness could result in misstatements of any of our financial statement accounts that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency 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 effective controls over the completeness and accuracy of our accounting for property and equipment. Specifically, our controls were not adequate to ensure (i) the timely and accurate depreciation of all property and equipment, (ii) the identification 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 reflected in our accounting records. This control deficiency resulted in certain inaccuracies in our accounting for property and equipment and in the restatement of our consolidated financial statements for the years ended December 31, 2004, 2003 and 2002; each of the quarters of 2004 and 2003; and the first three quarters of 2005. Additionally, this control deficiency 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 financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency 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 effective internal control over financial reporting as of December 31, 2005, based on the criteria in Internal Control-Integrated Framework issued by the COSO.

Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, 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 identified above by implementing changes to the Company’s internal control over financial reporting. Management has implemented, 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 certifications of information contained in SEC filings relating to their areas of responsibility;


	•	annual written questionnaires from senior employees and accounting staff with respect to awareness as to questionable business practices;

	•	improved education and training programs for all employees covering ethics, compliance, financial reporting and good business practices;

	•	additional guidelines with respect to senior management’s responsibilities for SEC filings, financial 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 financial reporting and accounting functions and operations and between the financial 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 reflected 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 fixed asset acquisitions. We have evaluated the design of these new procedures, placed them in operation for a sufficient period of time, and subjected them to appropriate tests in order to conclude that they are operating effectively. 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 financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 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.

PART III

The information required by Part III is omitted from this Report because we will file a definitive proxy statement pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference.


Item 10.	*Directors and Executive Officers 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 Beneficial Owners and Management and Related Stockholder Matters.*

The information required by this Item is incorporated herein by reference to the Proxy Statement.


Item 13.	*Certain Relationships and Related Transactions.*

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.

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 — Valuation and qualifying accounts is filed herewith on page S-1.

All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.

(a)(3) Exhibits

The following exhibits are filed herewith or incorporated by reference herein.


3	.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3	.2	Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3	.3	Amended and Restated Bylaws (filed March 19, 2002 as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
4	.1	Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (filed January 14, 1997 as Exhibit 2 to the Company’s Registration Statement on Form 8-A and incorporated herein by reference).
4	.2	Amendment to Rights Agreement dated as of October 23, 2001 (filed October 31, 2001 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001 and incorporated herein by reference).
4	.3	Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2).
4	.4	Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned by REMY Capital Partners III, L.P.(filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
10	.1	For additional material contracts, see Exhibits 4.1, 4.2 and 4.4.
10	.2	Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as amended (filed 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).*
10	.3	Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock Option Plan, as amended (filed November 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	.4	Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
10	.5	Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).*
10	.6	Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*


10	.7	Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(filed 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 (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).*
10	.9	1997 Stock Option Plan of DSI Industries, Inc. (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
10	.10	Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 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 (filed 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 (filed 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 (filed 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 (filed 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 (filed 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, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.17	Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed 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, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed 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, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.20	Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.21	Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III (filed on February 25, 2005 as Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).*


10	.22	Form of Indemnification 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. Huff, Terry H. Hunt, Kenneth R. Peak, Nadine C. Smith and John E. Vollmer III (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).*
10	.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 (filed 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 (filed on April 29, 2005 in the Company’s Current Report on Form 8-K and incorporated herein by reference).*
10	.25	Summary Description of Director Compensation (filed 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).*
14	.1	Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (filed 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).
21	.1	Subsidiaries of the Registrant.
23	.1	Consent of Independent Registered Public Accounting Firm.
31	.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31	.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32	.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page

Report of Independent Registered Public Accounting Firm		F-2
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2005 and 2004		F-5
Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003		F-6
Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		F-7
Consolidated Statements of Changes In Cash Flows for the years ended December 31, 2005, 2004 and 2003		F-8
Notes to Consolidated Financial Statements		F-9
Financial Statement Schedule		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 financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial 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 financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Patterson-UTI Energy, Inc. and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows 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 financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial 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 financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company restated its 2004 and 2003 consolidated financial statements.

Internal control over financial 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 effective internal control over financial reporting as of December 31, 2005, because the Company did not maintain (1) an effective control environment and (2) effective controls over property and equipment, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness 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 financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over

F-2

financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment as of December 31, 2005.

1. Control environment. The Company did not maintain an effective control environment based on the criteria established in the COSO framework. Specifically, 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, financial statements and documents together with forged approval signatures. This lack of an effective control environment allowed the Company’s former CFO to take inappropriate actions that resulted in certain transactions not being properly reflected in the Company’s consolidated financial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the first 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 effective 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 effective 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 benefit, specifically 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 benefits 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 employees, who worked under his supervision, to alter management reports related to property and equipment expenditures. Additionally, the Company’s former CFO created fictitious property and equipment approval forms with forged signatures. These actions had the effect 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 effective controls over the completeness and accuracy of their accounting for property and equipment. Specifically, the Company’s controls were not adequate to ensure (i) the timely and accurate depreciation of all property and equipment, (ii) the identification 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 reflected in their accounting records. This control deficiency resulted in certain inaccuracies in the Company’s accounting for property and equipment.

The control deficiencies described above resulted in the restatement of the Company’s consolidated financial statements for the years ended December 31, 2004, 2003 and 2002, each of the quarters of 2004 and 2003, and the first three quarters of 2005. Additionally, each of the control deficiencies 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 financial statement that would not be prevented or detected. Accordingly, the Company’s management has determined that each of these control deficiencies 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 financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

In our opinion, management’s assessment that Patterson-UTI Energy, Inc. did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the COSO. Also, in our opinion, because of the effects of the material weaknesses described above on the achievement of the objectives of the control criteria, Patterson-UTI Energy, Inc. has not maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — 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)
				2005			2004

				(In thousands,
				except share data)
ASSETS
Current assets:
	Cash and cash equivalents			$	136,398		$	112,371
	Accounts receivable, net of allowance for doubtful accounts of $2,199 and $1,909 at December 31, 2005 and 2004, respectively				422,002			214,097
	Inventory				27,907			17,738
	Deferred tax assets, net				26,382			15,991
	Other				25,168			26,836

			Total current assets		637,857			387,033
Property and equipment, at cost, net					1,053,845			765,019
Goodwill					99,056			99,056
Other					5,023			5,677

			Total assets	$	1,795,781		$	1,256,785


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable:
		Trade		$	113,226		$	54,553
		Accrued revenue distributions			13,379			11,297
		Other			5,294			2,309
	Accrued Federal and state income taxes payable				11,034			4,231
	Accrued expenses				112,476			79,163

			Total current liabilities		255,409			151,553
Deferred tax liabilities, net					169,188			140,475
Other					4,173			3,256

			Total liabilities		428,770			295,284

Commitments and contingencies					—			—
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				1,759			1,716
	Additional paid-in capital				672,151			597,280
	Deferred compensation				(9,287	)		(5,420	)
	Retained earnings				719,113			373,712
	Accumulated other comprehensive income, net of tax				8,565			7,350
	Treasury stock, at cost, 3,468,096 shares and 3,113,096 (affected by a two-for-one stock split) shares at December 31, 2005 and 2004, respectively				(25,290	)		(13,137	)

			Total stockholders’ equity		1,367,011			961,501

			Total liabilities and stockholders’ equity	$	1,795,781		$	1,256,785

The accompanying notes are an integral part of these consolidated financial statements.

F-5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


			Years Ended December 31,

						Restated (See Note 2)

			2005			2004			2003

			(In thousands, except per share data)
Operating revenues:
	Contract drilling		$	1,485,684		$	809,691		$	639,694
	Pressure pumping			93,144			66,654			46,083
	Drilling and completion fluids			122,011			90,557			69,230
	Oil and natural gas			39,616			33,867			21,163

				1,740,455			1,000,769			776,170

Operating costs and expenses:
	Contract drilling			776,313			556,869			475,224
	Pressure pumping			54,956			37,561			26,184
	Drilling and completion fluids			98,530			76,503			61,424
	Oil and natural gas			9,566			7,978			4,808
	Depreciation, depletion and impairment			156,393			122,800			100,834
	Selling, general and administrative			39,110			31,983			27,685
	Bad debt expense			1,231			897			259
	Embezzled funds and related expenses			20,043			19,122			17,849
	Other (including gain or loss on sale of assets)			3,017			(1,411	)		(4,379	)

				1,159,159			852,302			709,888

Operating income				581,296			148,467			66,282

Other income (expense):
	Interest income			3,551			1,140			1,116
	Interest expense			(516	)		(695	)		(292	)
	Other			428			235			1,870

				3,463			680			2,694

Income before income taxes and cumulative effect of change in accounting principle				584,759			149,147			68,976

Income tax expense (benefit):
	Current			194,918			39,952			15,324
	Deferred			17,101			14,849			9,996

				212,019			54,801			25,320

Income before cumulative effect of change in accounting principle				372,740			94,346			43,656
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287				—			—			(469	)

Net income			$	372,740		$	94,346		$	43,187

Net income per common share:
	Basic:
		Income before cumulative effect of change in accounting principle	$	2.19		$	0.57		$	0.27

		Cumulative effect of change in accounting principle	$	—		$	—		$	—

		Net income	$	2.19		$	0.57		$	0.27

	Diluted:
		Income before cumulative effect of change in accounting principle	$	2.15		$	0.56		$	0.27

		Cumulative effect of change in accounting principle	$	—		$	—		$	—

		Net income	$	2.15		$	0.56		$	0.26

	Weighted average number of common shares outstanding:
		Basic		170,426			166,258			161,272

		Diluted		173,767			169,211			164,572

The accompanying notes are an integral part of these consolidated financial statements.

F-6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY


																Accumulated
		Common Stock														Other
							Additional									Comprehensive
		Number					Paid-In			Deferred			Retained			Income			Treasury
		of Shares			Amount		Capital			Compensation			Earnings			(Loss)			Stock			Total

December 31, 2002, as previously reported			81,577		$	816	$	489,201		$	—		$	261,208		$	(1,839	)	$	(11,655	)	$	737,731
	Adjustment for effects of embezzlement (net of applicable income tax benefit of $7,622)(See Note 2)		—			—		—			—			(12,499	)		—			—			(12,499	)
	Other adjustments (net of applicable income tax benefit of $691) (See Note 2)		—			—		—			—			(1,659	)		675			—			(984	)

December 31, 2002, as restated (See Note 2)			81,577			816		489,201			—			247,050			(1,164	)		(11,655	)		724,248
	Exercise of stock options and warrants		906			9		10,277			—			—			—			—			10,286
	Tax benefit related to exercise of stock options		—			—		6,540			—			—			—			—			6,540
	Foreign currency translation adjustment, (net of tax of $3,220)		—			—		—			—			—			5,553			—			5,553
	Net income, as restated (See Note 2)		—			—		—			—			43,187			—			—			43,187

December 31, 2003, as restated (See Note 2)			82,483			825		506,018			—			290,237			4,389			(11,655	)		789,814
	Issuance of common stock for acquisition		1,388			14		49,462			—			—			—			—			49,476
	Issuance of restricted stock		189			2		6,640			(6,642	)		—			—			—			—
	Amortization of deferred compensation expense		—			—		—			1,222			—			—			—			1,222
	Exercise of stock options and warrants		2,580			25		24,494			—			—			—			—			24,519
	Tax benefit related to exercise of stock options		—			—		10,666			—			—			—			—			10,666
	Foreign currency translation adjustment, (net of tax of $1,716)		—			—		—			—			—			2,961			—			2,961
	Purchase of treasury stock		—			—		—			—			—			—			(1,482	)		(1,482	)
	Payment of cash dividend (see Note 12)		—			—		—			—			(10,021	)		—			—			(10,021	)
	Effect of two-for-one stock split (see Note 12)		84,986			850		—			—			(850	)		—			—			—
	Net income, as restated (See Note 2)		—			—		—			—			94,346			—			—			94,346

December 31, 2004, as restated (See Note 2)			171,626			1,716		597,280			(5,420	)		373,712			7,350			(13,137	)		961,501
	Issuance of restricted stock		305			3		8,040			(8,043	)		—			—			—			—
	Amortization of deferred compensation expense		—			—		—			2,825			—			—			—			2,825
	Forfeitures of restricted shares		(65	)		—		(1,351	)		1,351			—			—			—			—
	Exercise of stock options		4,043			40		43,434			—			—			—			—			43,474
	Tax benefit related to exercise of stock options		—			—		24,748			—			—			—			—			24,748
	Foreign currency translation adjustment, (net of tax of $705)		—			—		—			—			—			1,215			—			1,215
	Purchase of treasury stock		—			—		—			—			—			—			(12,153	)		(12,153	)
	Payment of cash dividend (see Note 12)		—			—		—			—			(27,339	)		—			—			(27,339	)
	Net income		—			—		—			—			372,740			—			—			372,740

December 31, 2005			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 financial statements.

F-7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS


				Years Ended December 31,

							Restated (See Note 2)

				2005			2004			2003

				(In thousands)
Cash flows from operating activities:
	Net income			$	372,740		$	94,346		$	43,187
	Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion and impairment				156,393			122,800			100,834
	Provision for bad debts				1,231			897			259
	Deferred income tax expense				17,101			14,849			9,996
	Tax benefit related to exercise of stock options				24,748			10,666			6,540
	Amortization of deferred compensation expense				2,825			1,222			—
	Gain on sale of assets				(1,253	)		(1,411	)		(1,927	)
	Cumulative effect of change in accounting principle, net of tax				—			—			(469	)
		Changes in operating assets and liabilities, net of business acquired:
			Accounts receivable		(208,248	)		(50,682	)		(55,791	)
			Federal income taxes receivable		7,068			15,734			11,155
			Inventory and other current assets		(9,402	)		(13,556	)		(8,984	)
			Accounts payable		60,860			12,861			12,322
			Accrued expenses		32,514			1,555			22,814
			Other liabilities		3,902			(6,090	)		5,015

		Net cash provided by operating activities			460,479			203,191			144,951

Cash flows from investing activities:
	Acquisitions, net of cash acquired				(73,577	)		(30,387	)		(40,832	)
	Purchases of property and equipment				(380,094	)		(174,589	)		(98,801	)
	Proceeds from sales of property and equipment				12,674			3,303			4,548
	Change in other assets				1,766			(1,766	)		(1,693	)

		Net cash used in investing activities			(439,231	)		(203,439	)		(136,778	)

Cash flows from financing activities:
	Purchase of treasury stock				(12,153	)		(1,482	)		—
	Dividends paid				(27,339	)		(10,021	)		—
	Line of credit issuance costs				—			(780	)		—
	Proceeds from exercise of stock options and warrants				43,474			24,519			10,286

		Net cash provided by financing activities			3,982			12,236			10,286

		Effect of foreign exchange rate changes on cash			(1,203	)		(100	)		(130	)

			Net increase in cash and cash equivalents		24,027			11,888			18,329
Cash and cash equivalents at beginning of year					112,371			100,483			82,154

Cash and cash equivalents at end of year				$	136,398		$	112,371		$	100,483

Supplemental disclosure of cash flow information:
	Net cash received (paid) during the year for:
			Interest expense	$	(418	)	$	(245	)	$	(292	)
			Income taxes		(156,709	)		(12,500	)		2,730

The accompanying notes are an integral part of these consolidated financial statements.

F-8

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Description of Business and Summary of Significant Accounting Policies


	*A description of the business and basis of presentation follows:*

Description of business — Patterson-UTI Energy, Inc., 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 fluids, completion fluids and related services to oil and natural gas operators offshore 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 — The Company’s former Chief Financial Officer (“CFO”) perpetrated an embezzlement over a period of more than five years. The accompanying 2004 and 2003 consolidated financial statements have been restated to reflect the effects 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 effects of the embezzlement prior to 2002, have been recognized as a reduction of retained earnings. The accompanying consolidated financial statements have also been restated for the effects of the correction of other errors that are immaterial both individually and in the aggregate (See Note 2).

Basis of presentation — As a result of the Company increasing its ownership of TMBR/Sharp Drilling, Inc. (“TMBR”) from 19.5% to 100% in 2004, the consolidated financial 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 effects of exchange rate changes are reflected 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 effect on equity. Historical earnings per share amounts included in the Statements of Income and elsewhere in these financial statements have been restated as if the two-for-one stock split had occurred on January 1, 2003.


	*A summary of the significant accounting policies follows:*

Principles of consolidation — The consolidated financial statements include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. The Company has no controlling financial interests in any entity which would require consolidation.

F-9

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Management estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

Revenue recognition — Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed contract method of accounting, as described below. The Company follows the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and risks therein, the Company follows the completed contract method of accounting for such arrangements. Under this method, all drilling revenues and expenses related to a well in progress are deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to exceed estimated total revenues. The Company recognizes reimbursements received from third parties for out-of-pocket expenses incurred as revenues and accounts for these out-of-pocket expenses as direct costs.

Accounts receivable — 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. Significant individual accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed individually for collectibility. Account balances, when determined to be uncollectible, are charged against the allowance.

Inventories — Inventories consist primarily of chemical products to be used in conjunction with the Company’s drilling and completion fluids activities. The inventories are stated at the lower of cost or market, determined by the first-in, first-out method.

Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depreciation is provided on the straight-line method over the estimated useful lives. The method of depreciation does not change when equipment becomes idle. The estimated useful lives, in years, are defined below.


	Useful Lives

Drilling rigs and related equipment		2-15
Office furniture		3-10
Buildings		5-20
Automotive equipment		2-7
Other		3-7

F-10

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (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 field. 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 field and undiscounted cash flow estimates are provided by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between its net book value and discounted cash flow. Unproved oil and natural gas properties are reviewed quarterly to 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 — Goodwill is considered to have an indefinite 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		$	141.7	$	109.4	$	93.7
Depletion expense			10.3		10.1		5.6
Amortization expense			—		0.1		0.1
Impairment of oil and natural gas properties			4.4		3.2		1.4

	Total	$	156.4	$	122.8	$	100.8

Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized.

Retirements — Upon disposition or retirement of property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is credited or charged to operations.

Investments in equity securities — Investments in equity securities are accounted for under the equity method of accounting.

Earnings per share — 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 — The asset and liability method is used in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences

F-11

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that such assets will be realized.

Stock based compensation — 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 reflected 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 effect 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):


		Years Ended December 31,

					Restated (See Note 2)

		2005			2004			2003

Net income, as reported		$	372,740		$	94,346		$	43,187
Add: Stock-based employee compensation expense recorded, net of forfeitures and taxes			1,795			773			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects(1)			(11,119	)		(12,304	)		(10,506	)

Pro forma net income		$	363,416		$	82,815		$	32,681

Earnings per share:
	Basic, as reported	$	2.19		$	0.57		$	0.27

	Basic, pro forma	$	2.13		$	0.50		$	0.20

	Diluted, as reported	$	2.15		$	0.56		$	0.26

	Diluted, pro forma	$	2.11		$	0.49		$	0.20

Weighted-average fair value per share of options granted(1)		$	6.33		$	6.25		$	5.59


(1)	See Note 13 for additional information regarding the computations presented here.

Statement of cash flows — For purposes of reporting cash flows, 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 — (Continued)

Recently Issued Accounting Standards — The Financial Accounting standards Board (“FASB”) issued Staff Position FIN 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”), an interpretation of FASB Statement No. 143, in March 2005. The statement clarifies 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 financial position or results of operations.

The FASB issued Statement of Financial Accounting Standard No. 151, Inventory Costs — an amendment of ARB No. 43, Chapter 4 (“SFAS 151”). SFAS 151 is effective, and will be adopted, for inventory costs incurred during fiscal 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 effect on our financial position or results of operations.

The FASB issued Statement of Financial Accounting standards No. 154, Accounting changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”). SFAS 154 is effective, and will be adopted for accounting changes made in fiscal 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 effects of the change. Adoption is not expected to have a material effect on the Company’s financial position or results of operations.

Reclassifications — Certain reclassifications have been made to the 2004 and 2003 consolidated financial statements in order for them to conform with the 2005 presentation.

F-13

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (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 financial 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 reflect losses incurred as a result of payments made to or for the benefit of Nelson that had been recognized in the Company’s accounting records and previously issued financial statements as payments for assets and services that were not received by the Company. Previously issued financial statements have also been restated for the effects 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.

Most of the embezzled funds result from Nelson causing the wiring of Company funds aggregating approximately $72.3 million, to, or for the benefit 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.

The total amount embezzled was approximately $77.5 million in cash, excluding any tax effects, beginning with the year ended December 31, 1998 through November 3, 2005 as follows (in thousands):


From 1998 to December 31, 2004			$	58,961
From January 1, 2005 to September 30, 2005(1)				12,193

	Total through September 30, 2005			71,154
From October 1, 2005 to November 3, 2005 (net of $1,500 repayment)(1)				6,350

		Total embezzlement	$	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 — (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.


			As of December 31,

						Effects of			Effects of
			Previously			Adjustment for			Other
			Reported			Embezzlement			Adjustments			Restated

			(In thousands)
2004:
	Property and equipment:
		At cost	$	1,400,848		$	(55,211	)	$	(6,866	)	$	1,338,771
		Accumulated depreciation		(571,973	)		1,348			(3,127	)		(573,752	)
		Net		828,875			(53,863	)		(9,993	)		765,019
	Goodwill			101,326			(2,270	)		—			99,056
	Total assets			1,322,911			(56,133	)		(9,993	)		1,256,785
	Federal and state income taxes payable			2,754			1,311			166			4,231
	Deferred tax liabilities, net			162,040			(22,159	)		594			140,475
	Liabilities			315,372			(20,848	)		760			295,284
	Retained earnings			415,489			(35,285	)		(6,492	)		373,712
	Accumulated other comprehensive income			11,611			—			(4,261	)		7,350
	Stockholders’ equity			1,007,539			(35,285	)		(10,753	)		961,501
2003:
	Federal and state income taxes receivable		$	12,667		$	(1,044	)	$	(170	)	$	11,453
	Property and equipment:
		At cost		1,161,536			(38,240	)		(4,992	)		1,118,304
		Accumulated depreciation		(467,905	)		890			(891	)		(467,906	)
		Net		693,631			(37,350	)		(5,883	)		650,398
	Goodwill			51,179			(146	)		—			51,033
	Total assets			1,084,114			(38,540	)		(6,053	)		1,039,521
	Deferred tax liabilities, net			143,309			(15,044	)		386			128,651
	Liabilities			264,365			(15,044	)		386			249,707
	Retained earnings			317,627			(23,496	)		(3,894	)		290,237
	Accumulated other comprehensive income			6,934			—			(2,545	)		4,389
	Stockholders’ equity			819,749			(23,496	)		(6,439	)		789,814

F-15

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The effects of the embezzlement and other adjustments on the Company’s results of operations and cash flows follow:


				Year Ended December 31,

							Effects of			Effects of
				Previously			Adjustment for			Other
				Reported			Embezzlement			Adjustments			Restated

				(In thousands, except per share amounts)
2004:
	Depreciation, depletion, amortization and impairment			$	119,395		$	(461	)	$	3,866		$	122,800
	Selling, general and administrative				32,007			(24	)		—			31,983
	Other (including gain or loss on sale of assets)				1,655			—			(244	)		1,411
	Embezzled funds expense				—			19,122			—			19,122
	Operating income				171,214			(18,637	)		(4,110	)		148,467
	Income before income taxes				171,894			(18,637	)		(4,110	)		149,147
	Income tax expense				63,161			(6,848	)		(1,512	)		54,801
	Net income				108,733			(11,789	)		(2,598	)		94,346
		Per common share:
			Basic		0.65			(0.07	)		(0.02	)		0.57
			Diluted		0.64			(0.07	)		(0.02	)		0.56
	Net cash provided by (used in):
		Operating activities			222,289			(19,098	)		—			203,191
		Investing activities			(222,537	)		19,098			—			(203,439	)
		Acquisitions			32,514			(2,127	)		—			30,387
	Purchases of property and equipment				191,560			(16,971	)		—			174,589

F-16

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


				Year Ended December 31,

							Effects of			Effects of
				Previously			Adjustment for			Other
				Reported			Embezzlement			Adjustments			Restated

				(In thousands, except per share amounts)
2003:
	Depreciation, depletion, amortization and impairment			$	97,998		$	(450	)	$	3,286		$	100,834
	Selling, general and administrative				27,709			(24	)		—			27,685
	Other (including gain or loss on sale of assets)				4,626			—			(247	)		4,379
	Embezzled funds expense				—			17,849			—			17,849
	Operating income				87,190			(17,375	)		(3,533	)		66,282
	Income before income taxes and cumulative effect of change in accounting principle				89,884			(17,375	)		(3,533	)		68,976
	Income tax expense				32,996			(6,378	)		(1,298	)		25,320
	Income before cumulative effect of change in accounting principle				56,888			(10,997	)		(2,235	)		43,656
	Net income				56,419			(10,997	)		(2,235	)		43,187
		Per common share:
			Basic		0.35			(0.07	)		(0.01	)		0.27
			Diluted		0.34			(0.07	)		(0.01	)		0.26
	Net cash provided by (used in):
		Operating activities			162,776			(17,825	)		—			144,951
		Investing activities			(154,603	)		17,825			—			(136,778	)
	Purchases of property and equipment				116,626			(17,825	)		—			98,801


3.	Acquisitions


	*2005 Acquisitions*

Key Energy Services, Inc. — 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 fleet 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 — On June 17, 2005, the Company acquired one land-based drilling rig for $3.6 million and on September 29, 2005, the Company acquired five 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. — 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 financial 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 — (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		$	40,423
Patterson-UTI shares issued at $17.82 per share (4,447 TMBR shares X .624332 exchange ratio X $17.82)			49,476
1,059 TMBR shares previously acquired by the Company			19,771
Acquisition costs			10,511
Less: Cash acquired			(7,909	)

	Total purchase price	$	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		$	7,181
Fixed assets			60,784
Other long term assets			172
Deferred tax assets			13,080
Goodwill			48,020
Current liabilities			(7,080	)
Other long term liabilities			(1,090	)
Deferred tax liability			(8,795	)

	Total purchase allocation	$	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 financial information as if the acquisition had been completed on January 1, 2003 (in thousands, except per share amounts):


		Restated (See Note 2)

		2004		2003

Revenue		$	1,005,357	$	818,774
Income before cumulative effect of change in accounting principle			94,047		45,430
Net income			94,047		44,961
Earnings per share:
	Basic	$	0.57	$	0.28

	Diluted	$	0.56	$	0.27

F-18

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*2003 Acquisitions*

SEI Drilling Company — 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. — 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 — 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 — 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 — 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 — 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 effects of foreign currency translation adjustments for the years ended December 31, 2005, 2004 and 2003 (in thousands):


			Restated (See Note 2)

	2005		2004		2003

Net income	$	372,740	$	94,346	$	43,187
Other comprehensive income:
Foreign currency translation adjustment related to Canadian operations		1,215		2,961		5,553

Comprehensive income	$	373,955	$	97,307	$	48,740

F-19

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Property and Equipment

Property and equipment consisted of the following at December 31, 2005 and 2004 (in thousands):


				Restated
				(See Note 2)
	2005			2004

Equipment	$	1,633,911		$	1,239,519
Oil and natural gas properties		79,079			82,711
Buildings		22,490			12,892
Land		5,611			3,649

		1,741,091			1,338,771
Less accumulated depreciation and depletion		(687,246	)		(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)
					2005		2004

Drilling:
	Goodwill at beginning of period				$	89,092	$	41,069
		Goodwill in TMBR				—		48,020
		Other				—		3

			Goodwill at end of period			89,092		89,092

Drilling and completion fluids:
	Goodwill at beginning of period					9,964		9,964
		Changes to goodwill				—		—

			Goodwill at end of period			9,964		9,964

				Total goodwill	$	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 financial 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 — (Continued)

The following tables present the effects of all restatements for the year ended December 31, 2003 (in thousands, except per share amounts):


		Previously		Effects of
		Reported		Adjustment			Effects of			Effects of
		on Cost		to Equity			Adjustment for			Other
		Basis		Method			Embezzlement			Adjustments			Restated

Other income (loss)		$	143	$	1,727		$	—		$	—		$	1,870
Deferred income tax expense		$	17,274	$	634		$	(6,615	)	$	(1,297	)	$	9,996
Net income		$	55,326	$	1,093		$	(10,997	)	$	(2,235	)	$	43,187
Comprehensive income, net of tax		$	65,689	$	(497	)	$	(10,997	)	$	(5,455	)	$	48,740
Net income per common share:
	Basic	$	0.34	$	0.01		$	(0.07	)	$	(0.01	)	$	0.27
	Diluted	$	0.34	$	0.01		$	(0.07	)	$	(0.01	)	$	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 benefits	$	33,816	$	21,245
Workers’ compensation liability		47,107		38,677
Sales, use and other taxes		9,484		5,863
Insurance, other than workers’ compensation		11,365		7,061
Other		10,704		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 year	$	2,358		$	1,163
Liabilities incurred*		101			1,277
Liabilities settled		(808	)		(153	)
Accretion expense		74			71

Asset retirement obligation at end of year	$	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 effect of change in accounting principle of approximately $469,000, net of tax, was recorded in the first quarter of 2003.

F-21

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	Notes Payable

The Company replaced its prior credit facility in December 2004 with a five-year, $200 million unsecured revolving line of credit (“LOC”). Interest is to be paid on outstanding LOC balances at a floating 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 benefit 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 — The Company’s contract services and oil and natural gas exploration and production operations are subject to inherent risks, including blowouts, cratering, fire and explosions which could result in personal injury or death, suspended drilling operations, damage to, or destruction of equipment, damage to producing formations and pollution or other environmental hazards.

As a protection against these hazards, the Company maintains general liability insurance coverage of $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 financial 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 sufficient to protect the Company against liability for all consequences of well disasters, extensive fire damage, or damage to the environment. The Company also carries insurance to cover physical damage to, or loss of, its rigs; however, it does not carry insurance against loss of earnings resulting from such damage or loss.

In December 2005, two purported derivative actions were filed in Texas state court in Scurry County, Texas, against the directors of the Company, alleging that the directors breached their fiduciary 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 — (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 effect on its financial condition.

Other Matters — Effective January 29, 2004, the Company entered into Change in Control Agreements with its Chairman of the Board, Chief Executive Officer, 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 notifies the Key Employee at least ninety days before the end of such renewal period that the term will not be extended. If a change in control of the Company occurs during the term of the agreement and the Key Employee’s employment is terminated (i) by the Company other than for cause or other than automatically as a result of death, disability or retirement or (ii) by the Key Employee for good reason (as those terms are defined in the Change in Control Agreements), then the Key Employee shall 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 fiscal years immediately preceding a change in control (such bonus payment prorated for the portion of the fiscal year preceding the termination date);

	•	a payment equal to 2.5 times (in the case of the Chairman of the Board, Chief Executive Officer and President and Chief Operating Officer) or 1.5 times (in the case of the Senior Vice Presidents) of the sum of (i) the highest annual salary in effect for such Key Employee and (ii) the average of the three annual bonuses earned by the Key Employee for the three fiscal years preceding the termination date; and

	•	continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board, Chief Executive Officer and President and Chief Operating Officer) 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 benefits received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the gross-up payment.


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 reflect 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 — (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 effect 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, financial 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 reflect 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 — 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 — (Continued)

intend to grant any further options under such plans. At December 31, 2005, the Company’s stock option plans were as follows:


	Options				Options
	Authorized		Options		Available
Plan Name	for Grant		Outstanding		for Grant

Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”)(1)		6,250,000		—		5,464,217
Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”)		—		5,010,603		—
Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (“2001 Plan”)		—		888,304		—
Amended and Restated Non-Employee Director Stock Option Plan of Patterson-UTI Energy, Inc. (“Non- Employee Director Plan”)		—		200,000		—
1997 Stock Option Plan of DSI Industries, Inc. (“DSI Plan”)		—		536		—
Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (“1996 Plan”)		—		95,800		—
Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as amended (“1993 Plan”)		—		142,800		—


(1)	Plan is for the benefit of employees of the Company, including officers 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 officers 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 defined 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 — Options granted under the 1997 Plan vest over three or five 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 — Options granted under the 2001 Plan vest over five 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 — (Continued)

Non-Employee Director Plan — Options granted under the Non-Employee Director Plan vest on the first anniversary of the option grant. Non-Employee Director Plan options have five 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 — 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 — Options granted under the 1996 plan vested over one, four and five years as dictated by the Compensation Committee. These options had terms of five 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 — Options granted under the 1993 Plan, typically had terms of 10 years and vested over five years in 20% increments beginning at the end of the first year. These options vest in the event of a change of control as defined 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			Weighted		No. of			Weighted		No. of			Weighted
		Shares of			Average		Shares of			Average		Shares of			Average
		Underlying			Exercise		Underlying			Exercise		Underlying			Exercise
		Options			Price		Options			Price		Options			Price

Outstanding at beginning of year			10,006		$	12.24		12,276		$	10.31		12,277		$	8.81
	Granted		675			24.63		640			19.19		1,830			16.24
	Exercised		(4,044	)		10.75		(2,852	)		5.55		(1,736	)		5.92
	Surrendered/Expired		(299	)		15.23		(58	)		8.76		(95	)		9.99

Outstanding at end of year			6,338		$	14.37		10,006		$	12.24		12,276		$	10.31

Exercisable at end of year			4,809		$	13.33		6,377		$	11.68		5,972		$	8.15

F-26

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information about stock options outstanding at December 31, 2005:


	Options Outstanding						Options Exercisable

			Weighted
			Average		Weighted				Weighted
			Remaining		Average				Average
	Number		Contracted		Exercise		Number		Exercise
Range of Exercise Prices	Outstanding		Life		Price		Exercisable		Prices

$1.5625 to $ 2.50		136,100		3.25	$	2.24		136,100	$	2.24
$ 2.51 to $ 5.00		41,300		2.16	$	4.94		41,300	$	4.94
$ 5.01 to $ 7.50		53,436		1.65	$	7.36		53,436	$	7.36
$ 7.51 to $10.00		1,256,470		5.46	$	8.01		879,170	$	8.03
$ 10.01 to $12.50		42,500		2.05	$	11.48		42,500	$	11.48
$ 12.51 to $15.00		1,849,904		6.58	$	13.43		1,680,771	$	13.34
$ 15.01 to $24.63		2,958,333		7.68	$	18.53		1,976,111	$	16.81

		6,338,043		6.70	$	14.37		4,809,388	$	13.33

Pro Forma Stock-Based Compensation Disclosure — 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 defined 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 different 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 effects 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 — 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 — (Continued)

Tabular Summary — 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
		Shares		Exercise Price

Granted
	2005		675	$	24.63
	2004		640	$	19.19
	2003		1,830		16.24
Exercised
	2005		4,044	$	10.75
	2004		3,502	$	7.00
	2003		1,941		6.46
Surrendered
	2005		299	$	15.23
	2004		58	$	8.76
	2003		95		9.99
Outstanding at Year End
	2005		6,338	$	14.37
	2004		10,006	$	12.24
	2003		12,926		10.47
Exercisable at Year End
	2005		4,809	$	13.33
	2004		6,377	$	11.68
	2003		6,622		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 — (Continued)


15.	Income Taxes

Components of the income tax provision applicable for Federal, state and foreign income taxes are as follows (in thousands):


				Restated (See Note 2)

		2005		2004		2003

Federal income tax expense (benefit):
	Current	$	174,635	$	32,686	$	14,073
	Deferred		14,182		12,366		7,794

			188,817		45,052		21,867

State income tax expense (benefit):
	Current		13,045		2,031		1,233
	Deferred		1,431		1,555		(487	)

			14,476		3,586		746

Foreign income tax expense (benefit):
	Current		7,238		5,235		18
	Deferred		1,488		928		2,689

			8,726		6,163		2,707

Total:
	Current		194,918		39,952		15,324
	Deferred		17,101		14,849		9,996

Total income tax expense		$	212,019	$	54,801	$	25,320

The difference between the statutory Federal income tax rate and the effective income tax rate is summarized as follows:


				Restated
				(See Note 2)

	2005			2004			2003

Statutory tax rate		35.0	%		35.0	%		35.0	%
State income taxes		1.8			1.6			1.5
Permanent differences		(0.6	)		0.4			0.8
Other, net		0.1			(0.3	)		(0.6	)

Effective tax rate		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 differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Company expects the deferred tax assets at December 31, 2005 to be realized as a result of the reversal during the carryforward period of existing taxable temporary differences 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 — (Continued)

The tax effect of significant temporary differences representing deferred tax assets and liabilities and changes therein were as follows (in thousands):


									Restated (See Note 2)

			December 31,			Net			December 31,			Net			December 31,			Net			January 1,
			2005			Change			2004			Change			2003			Change			2003

Deferred tax assets:
	Current:
		Federal net operating loss carryforwards	$	1,870		$	—		$	1,870		$	1,870		$	—		$	—		$	—
		Workers’ compensation allowance		19,461			4,584			14,877			1,545			13,332			6,159			7,173
		AMT credit		—			—			—			(602	)		602			—			602
		Other		11,364			4,386			6,978			1,238			5,740			(1,775	)		7,515

				32,695			8,970			23,725			4,051			19,674			4,384			15,290

	Non-current:
		Federal net operating loss carryforwards		2,245			(1,870	)		4,115			4,115			—			—			—
		AMT credit		118			—			118			118			—			—			—
		Federal benefit of foreign deferred tax liabilities		8,196			1,488			6,708			933			5,775			2,019			3,756
		Federal benefit of state deferred tax liabilities		4,232			717			3,515			421			3,094			1,275			1,819
		Embezzled funds expense		—			(22,178	)		22,178			7,193			14,985			6,713			8,272
		Other		937			174			763			763			—			—			—

				15,728			(21,669	)		37,397			13,543			23,854			10,007			13,847

Total deferred tax assets				48,423			(12,699	)		61,122			17,594			43,528			14,391			29,137

Deferred tax liabilities:
	Current:
		Other		(6,313	)		1,421			(7,734	)		(4,509	)		(3,225	)		(3,225	)		—

	Non-current:
		Property and equipment basis difference		(179,725	)		(6,381	)		(173,344	)		(25,534	)		(147,810	)		(16,683	)		(131,127	)
		Other		(5,191	)		(663	)		(4,528	)		167			(4,695	)		(4,795	)		100

				(184,916	)		(7,044	)		(177,872	)		(25,367	)		(152,505	)		(21,478	)		(131,027	)

Total deferred tax liabilities				(191,229	)		(5,623	)		(185,606	)		(29,876	)		(155,730	)		(24,703	)		(131,027	)

Net deferred tax liability			$	(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 — (Continued)

Other deferred tax assets consist primarily of various allowance accounts and tax deferred expenses expected to generate future tax benefit 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.


16.	Employee Benefits

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 fluids 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 offered. These segments have separate management teams which report to the Company’s chief executive officer and have distinct and identifiable revenues and expenses.

Contract Drilling — 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 — The Company provides pressure pumping services primarily in the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Well stimulation involves processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. Cementing is the process of inserting material between the hole and the pipe to center and stabilize the pipe in the hole.

Drilling and Completion Fluids — The Company provides drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. The drilling fluids 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 fluids in October 2000 with the acquisition of the drilling and completion fluids division of Ambar, Inc., which had operations in the coastal areas of Texas, Louisiana and in the Gulf of Mexico.

Oil and Natural Gas — 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 — (Continued)

The following tables summarize selected financial information relating to the Company’s business segments (in thousands):


			Years Ended December 31,

						Restated (See Note 2)

			2005			2004			2003

Revenues:
	Contract drilling(a)		$	1,488,485		$	815,683		$	640,788
	Pressure pumping			93,144			66,654			46,083
	Drilling and completion fluids(b)			122,309			90,858			69,286
	Oil and natural gas			39,616			33,867			21,163

Total segment revenues				1,743,554			1,007,062			777,320
	Elimination of intercompany revenues(a)(b)			(3,099	)		(6,293	)		(1,150	)

Total revenues			$	1,740,455		$	1,000,769		$	776,170

Income (loss) before income taxes:
	Contract drilling		$	572,562		$	146,626		$	72,814
	Pressure pumping			21,664			16,747			10,442
	Drilling and completion fluids			11,947			4,202			(1,920	)
	Oil and natural gas			13,405			10,764			7,784

				619,578			178,339			89,120
	Corporate and other			(14,223	)		(10,750	)		(7,441	)
	Other charges(c)			(4,016	)		—			2,452
	Embezzled funds and related expenses(d)			(20,043	)		(19,122	)		(17,849	)
	Interest income			3,551			1,140			1,116
	Interest expense			(516	)		(695	)		(292	)
	Other			428			235			1,870

		Income before income taxes	$	584,759		$	149,147		$	68,976

Identifiable assets:
	Contract drilling		$	1,421,779		$	961,873		$	766,039
	Pressure pumping			72,536			49,145			35,066
	Drilling and completion fluids			90,904			62,970			56,215
	Oil and natural gas			60,785			62,984			37,111

				1,646,004			1,136,972			894,431
	Corporate and other(e)			149,777			119,813			145,090

Total assets			$	1,795,781		$	1,256,785		$	1,039,521

Depreciation, depletion and impairment:
	Contract drilling(d)		$	131,740		$	101,779		$	87,255
	Pressure pumping			7,094			5,112			3,774
	Drilling and completion fluids			2,368			2,156			2,279
	Oil and natural gas			14,456			13,309			7,082

				155,658			122,356			100,390
	Corporate and other			735			444			444

Total depreciation, depletion and impairment			$	156,393		$	122,800		$	100,834

F-32

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Years Ended December 31,

				Restated (See Note 2)

		2005		2004		2003

Capital expenditures:
	Contract drilling(d)	$	329,073	$	140,945	$	77,350
	Pressure pumping		25,508		17,705		10,524
	Drilling and completion fluids		3,042		1,488		912
	Oil and natural gas		17,163		14,451		10,015
	Corporate and other		5,308		—		—

Total capital expenditures		$	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 fluids 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 specific 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 five 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)

F-33

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (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)

			1st			2nd			3rd			4th
			Quarter			Quarter			Quarter			Quarter

2005
Operating revenues			$	350,593		$	389,922		$	468,739		$	531,201
Operating income:
	As previously reported		$	94,252		$	122,416		$	173,511		$	—
	Adjustment for effects of embezzlement			(1,381	)		(4,717	)		(4,721	)		—
	Other adjustments			(1,038	)		(1,048	)		(1,344	)		—

			$	91,833		$	116,651		$	167,446		$	205,366

Net income:
	As previously reported		$	59,748		$	77,665		$	110,135		$	—
	Adjustment for effects of embezzlement			(872	)		(2,978	)		(2,981	)		—
	Other adjustments			(656	)		(661	)		(849	)		—

			$	58,220		$	74,026		$	106,305		$	134,189

Earnings per share:
	Basic:
		As previously reported	$	0.35		$	0.46		$	0.64		$	—
		Adjustment for effects of embezzlement	$	(0.01	)	$	(0.02	)	$	(0.02	)	$	—
		Other adjustments	$	—		$	—		$	—		$	—
			$	0.34		$	0.44		$	0.62		$	0.78
	Diluted:
		As previously reported	$	0.35		$	0.45		$	0.63		$	—
		Adjustment for effects of embezzlement	$	(0.01	)	$	(0.02	)	$	(0.02	)	$	—
		Other adjustments	$	—		$	—		$	—		$	—
			$	0.34		$	0.43		$	0.61		$	0.77


		Restated (See Note 2)

		1st			2nd			3rd			4th
		Quarter			Quarter			Quarter			Quarter

2004
Operating revenues		$	218,779		$	234,510		$	259,174		$	288,306
Operating income:
	As previously reported	$	32,510		$	30,799		$	47,408		$	60,497
	Adjustment for effects of embezzlement		(5,013	)		(3,470	)		(4,642	)		(5,512	)
	Other adjustments		(927	)		(1,002	)		(1,024	)		(1,157	)

		$	26,570		$	26,327		$	41,742		$	53,828

F-34

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			Restated (See Note 2)

			1st			2nd			3rd			4th
			Quarter			Quarter			Quarter			Quarter

Net income:
	As previously reported		$	20,682		$	19,607		$	29,964		$	38,480
	Adjustment for effects of embezzlement			(3,164	)		(2,186	)		(2,921	)		(3,518	)
	Other adjustments			(585	)		(631	)		(645	)		(737	)

			$	16,933		$	16,790		$	26,398		$	34,225

Earnings per share:
	Basic:
		As previously reported	$	0.12		$	0.12		$	0.18		$	0.23
		Adjustment for effects of embezzlement	$	(0.02	)	$	(0.01	)	$	(0.02	)	$	(0.02	)
		Other adjustments	$	—		$	—		$	—		$	—
			$	0.10		$	0.10		$	0.16		$	0.20
	Diluted:
		As previously reported	$	0.12		$	0.12		$	0.18		$	0.23
		Adjustment for effects of embezzlement	$	(0.02	)	$	(0.01	)	$	(0.02	)	$	(0.02	)
		Other adjustments	$	—		$	—		$	—		$	—
			$	0.10		$	0.10		$	0.16		$	0.20


19.	Concentrations of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of demand deposits, temporary cash investments and trade receivables.

The Company believes that it places its demand deposits and temporary cash investments with high credit quality financial 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	$	1,066		$	2,023
Deposits in FDIC and SIPC-insured institutions over $100,000		153,261			131,427
Deposits in Foreign Banks		2,513			—

		156,840			133,450
Less outstanding checks and other reconciling items		(20,442	)		(21,079	)

Cash and cash equivalents	$	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 diversification 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 significant 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 approximate fair value due to the short-term maturity of these assets.

F-35

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


20.	Related Party Transactions

Joint Operation of Oil and Natural Gas Properties — The Company operates certain oil and natural gas properties in which certain of its affiliated 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, affiliated 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 affiliated persons was the same price at which working interests were sold to unaffiliated persons. The affiliated 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 affiliated persons of approximately $1.5 million and $1.2 million and a receivable from the affiliated persons of approximately $1.2 million and $856,000 at December 31, 2005 and 2004, respectively.

Other — 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 Transportation (“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 benefit of Jonathan D. Nelson, our former CFO.

F-36

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


				Charged to
		Beginning		Costs and				Ending
Description		Balance		Expenses(1)		Deductions(2)		Balance

		(In thousands)
Year Ended December 31, 2005
Deducted from asset accounts:
	Allowance for doubtful accounts	$	1,909	$	1,231	$	941	$	2,199
Year Ended December 31, 2004
Deducted from asset accounts:
	Allowance for doubtful accounts	$	2,133	$	897	$	1,121	$	1,909
Year Ended December 31, 2003
Deducted from asset accounts:
	Allowance for doubtful accounts	$	3,144	$	259	$	1,270	$	2,133


(1)	Net of recoveries.

(2)	Uncollectible accounts written off.

S-1

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.


	PATTERSON-UTI ENERGY, INC.


	By:	/s/ CLOYCE A. TALBOTT



	Cloyce A. Talbott
	Chief Executive Officer

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				Chairman of the Board

/s/ CLOYCE A. TALBOTT Cloyce A. Talbott (Principal Executive Officer)				Chief Executive Officer and Director

/s/ A. GLENN PATTERSON A. Glenn Patterson				President, Chief Operating Officer and Director

/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 Officer)				Senior Vice President — Corporate Development, Chief Financial Officer, Secretary and Treasurer

/s/ ROBERT C. GIST Robert C. Gist				Director

/s/ CURTIS W. HUFF Curtis W. Huff				Director

/s/ TERRY H. HUNT Terry H. Hunt				Director

/s/ KENNETH R. PEAK Kenneth R. Peak				Director

/s/ NADINE C. SMITH Nadine C. Smith				Director

EXHIBIT INDEX


3	.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3	.2	Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3	.3	Amended and Restated Bylaws (filed March 19, 2002 as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
4	.1	Rights Agreement dated January 2, 1997, between Patterson Energy, Inc. and Continental Stock Transfer & Trust Company (filed January 14, 1997 as Exhibit 2 to the Company’s Registration Statement on Form 8-A and incorporated herein by reference).
4	.2	Amendment to Rights Agreement dated as of October 23, 2001 (filed October 31, 2001 as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001 and incorporated herein by reference).
4	.3	Restated Certificate of Incorporation, as amended (See Exhibits 3.1 and 3.2).
4	.4	Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned by REMY Capital Partners III, L.P.(filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference).
10	.1	For additional material contracts, see Exhibits 4.1, 4.2 and 4.4.
10	.2	Patterson-UTI Energy, Inc., 1993 Stock Incentive Plan, as amended (filed 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).*
10	.3	Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock Option Plan, as amended (filed November 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	.4	Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (filed November 27, 2002 as Exhibit 4.4 to Post Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
10	.5	Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).*
10	.6	Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).*
10	.7	Amended and Restated Patterson-UTI Energy, Inc. Non-Employee Director Stock Option Plan(filed 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 (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60466) and incorporated herein by reference).*
10	.9	1997 Stock Option Plan of DSI Industries, Inc. (filed July 25, 2001 as Exhibit 4.4 to Post-Effective Amendment No. 1 to the Company’s Registration Statement on Form S-8 (File No. 333-60470) and incorporated herein by reference).*
10	.10	Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 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 (filed 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 (filed 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 (filed 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 (filed 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 (filed 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, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.17	Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and A. Glenn Patterson (filed 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, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Cloyce A. Talbott (filed 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, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.20	Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.21	Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III (filed on February 25, 2005 as Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).*
10	.22	Form of Indemnification 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. Huff, Terry H. Hunt, Kenneth R. Peak, Nadine C. Smith and John E. Vollmer III (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).*
10	.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 (filed 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 (filed on April 29, 2005 in the Company’s Current Report on Form 8-K and incorporated herein by reference).*
10	.25	Summary Description of Director Compensation (filed 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).*
14	.1	Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (filed 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).
21	.1	Subsidiaries of the Registrant.
23	.1	Consent of Independent Registered Public Accounting Firm.


31	.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31	.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32	.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.