PATTERSON UTI ENERGY INC (Form: 10-K, Received: 02/25/2005 13:18:39)

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, 2004

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 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 an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter was $2,648,551,638, calculated by reference to the closing price of $16.67 for the common stock on the Nasdaq National Market on that date.

As of February 24, 2005, the registrant had outstanding 168,651,600 shares of common stock, $.01 par value, its only class of voting common stock.

Documents incorporated by reference:

Definitive Proxy Statement for the 2005 Annual Meeting of Stockholders (Part III).

TABLE OF CONTENTS


PART I
	Items 1 and 2. Business and Properties.
	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.
SIGNATURES
EXHIBIT INDEX
Asset Purchase Agreement
Form of Letter Agreement Regarding Termination
Summary Description of 2003 Cash Bonus Plan
Summary Description of Director Compensation
Subsidiaries
Consent of Independent Accountants - PricewaterhouseCoopers LLP
Consent of Independent Petroleum Engineer - M. Brian Wallace, P.E.
Certification of CEO
Certification of CFO
Certification of CEO and CFO - Section 906

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: “Forward Looking Statements and Cautionary Statements for Purposes of the ’Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” beginning on page 14.

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 through our Internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

PART I


Items 1 and 2.	*Business and Properties.*

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, and

	•	Western Canada (Alberta, British Columbia and Saskatchewan).

As of December 31, 2004, we had a drilling fleet of 361 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 Texas, South Texas, Southeastern New Mexico, Utah and Mississippi.

Patterson/ UTI Merger

Patterson Energy, Inc. and UTI Energy Corp. consummated a merger on May 8, 2001. The transaction was treated as a reorganization within the meaning of Section 368 (a) of the Internal Revenue Code of 1986, as amended, and accounted for as a pooling of interests for financial accounting purposes. Historical financial statements and related financial and statistical data contained in this Report have been restated to provide for the retroactive effect of the merger.

Industry Segments

Our revenues, operating results and identifiable operating assets are 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 2004, 2003 and 2002,

	•	the pressure pumping segment had operating profits in 2004, 2003 and 2002,

	•	the drilling and completion fluids segment had an operating profit in 2004 and operating losses in 2003 and 2002, and

	•	the oil and natural gas segment had operating profits in 2004, 2003 and 2002.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 16 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, 2004, we owned 361 drilling rigs which were based in the following regions:


	•	149 in the Permian Basin region (West Texas and Southeastern New Mexico),

	•	55 in South Texas,

	•	42 in the Ark-La-Tex region and Mississippi,

	•	77 in the Mid-Continent region (Oklahoma and North Central Texas),

	•	21 in the Rocky Mountain region (Colorado, Utah and Wyoming), and

	•	17 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, 40 are SCR electric rigs and 321 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 2004, 2003 and 2002, we spent approximately $158 million, $95 million and $69 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.

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. We generally receive a lower rate when the drilling rig is moving, or when drilling operations are interrupted or restricted by conditions beyond our control. 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.

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.

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


	Years Ended December 31,

Type of Revenues	2004			2003			2002

Daywork		88	%		83	%		82	%
Footage		6			7			11
Turnkey		6			10			7

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


	Years Ended December 31,

	2004			2003			2002

Average rigs owned		359			336			323
Average rigs operating(1)		211			188			126
Average rig utilization rate		59	%		56	%		39	%
Number of rigs operated		259			226			230
Number of wells drilled		3,534			3,017			2,012


(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, 2004 follows:


Depth Rating (Ft.)		Mechanical		Electric

4,000 to 9,999			63		—
10,000 to 11,999			68		2
12,000 to 14,999			126		7
15,000 to 30,000			64		31

	Totals		321		40

At December 31, 2004, we owned 288 trucks and 360 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, 2004 follows:


	•	23 cement pumper trucks,

	•	26 fracturing pumper trucks,

	•	24 nitrogen pumper trucks,

	•	13 blender trucks,

	•	12 bulk acid trucks,

	•	28 bulk cement trucks,

	•	8 bulk nitrogen trucks,

	•	35 bulk sand trucks,

	•	11 connection trucks, and

	•	3 acid pumper trucks.

Drilling and Completion Fluids Operations

General — 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. 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	Completion

barite		calcium chloride
bentonite		calcium bromide 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 20 trucks and 71 trailers and lease another 22 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 Texas, 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. Management is assessing the acquired undeveloped prospects and will make determinations as to the extent future capital will be expended to develop those prospects. We also selectively acquire leasehold acreage and producing properties.

Oil and Natural Gas Reserves — Estimates, derived from reserve reports provided by M. Brian Wallace, an independent petroleum engineer, of our proved reserves and estimated future net revenues from our proved reserves as of December 31, 2004, 2003 and 2002 are in the table below. The estimates were based upon production histories, current market prices for oil and natural gas, and other geologic, ownership and engineering data provided by us. The present values (discounted at 10% before income taxes) of estimated future net revenues shown in the table are not intended to represent the current market value of the estimated oil and natural gas reserves. For further information concerning the present value of estimated future net revenues from these proved reserves, see Note 20 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if they are supported by either actual production or conclusive formation tests and future production is determined to be economical.


		As of December 31,

		2004		2003		2002

		(In thousands)
Proved Reserves:
	Oil (Bbls)		1,714		1,147		1,227
	Gas (Mcf)		8,246		5,267		6,240
	Total (BOE)		3,088		2,025		2,267
Estimated future net revenues before income taxes		$	84,952	$	47,873	$	46,016
Present value of estimated future net revenues before income taxes, discounted at 10%		$	59,519	$	34,371	$	32,308
Standardized measure of discounted future net cash flows(1)		$	37,542	$	23,950	$	21,100


(1)	For the calculation of standardized measure of discounted future net cash flows, see Note 20 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

A barrel (Bbl) of oil is 42 U.S. gallons and represents the basic unit for measuring production of crude oil and condensate.

An Mcf of natural gas refers to a volume of 1,000 cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring volumes of produced natural gas. A barrel of equivalent (BOE) in reference to natural gas equivalents is determined using the rate of six Mcf of natural gas to one Bbl of crude oil or condensate.

Production — At December 31, 2004, we held a working interest in 440 productive wells, of which 266 were considered oil and 174 were considered natural gas. A productive well is a well producing oil or natural gas in commercial quantities. A working interest is the operating interest under an oil or natural gas lease which gives the owner the right to explore for and produce oil or natural gas from the lease. We were the operator of 199 of these productive wells at December 31, 2004. The following table sets forth our average net oil and natural gas production, average sales price and average production costs. Production costs are costs incurred to operate and maintain our wells and related equipment. These costs include labor, well service and repair, utilities, field supervision, property taxes, production and severance taxes and related charges.


		Years Ended December 31,

		2004		2003		2002

Average net daily production:
	Oil (Bbls)		1,071		788		794
	Gas (Mcf)		7,429		5,656		5,109
	Total (BOE)		2,309		1,731		1,646
Average sales prices:
	Oil (per Bbl)	$	39.12	$	30.54	$	25.02
	Gas (per Mcf)		5.81		4.97		2.91
Average production costs (per BOE)		$	7.18	$	5.51	$	5.11

Productive Wells — The number of productive wells in which we held a working interest as of December 31, 2004 are in the table below. One or more completions in the same well bore are reflected as one well.


		Productive
		Wells

		Gross		Net

Oil			266		53.26
Gas			174		24.65

	Total		440		77.91

Developed and Undeveloped Acreage — Developed and undeveloped acreage in which we owned a working interest at December 31, 2004 follows:


		Developed				Undeveloped
		Acreage				Acreage

Location		Gross		Net		Gross		Net

Texas			74,379		14,027		40,484		10,551
Kansas			320		45		—		—
Louisiana			1,920		96		—		—
New York			160		131		—		—
New Mexico			19,959		3,943		23,693		3,943
Mississippi			2,920		668		8,366		1,840
Oklahoma			640		19		—		—
Pennsylvania			880		129		—		—
Utah			—		—		13,292		1,994

	Total		101,178		19,058		85,835		18,328

Undeveloped acreage is leased acres on which wells have not been drilled to a point that would permit production of commercial quantities of oil and natural gas. Developed acreage is leased acres that have been assigned to productive wells. Our gross acreage is the total number of acres in which we own a working interest, regardless of the size of our working interest in the acreage. Our net acreage is the gross acreage proportionally reduced to our working interest percentage in the acreage.

Many of our leases summarized in the table above as undeveloped acreage will expire at the end of their respective primary terms unless production has been obtained from the acreage prior to that date. If production is obtained, the lease will remain in effect until the cessation of production. Undeveloped acreage subject to leases summarized in the table above are scheduled to expire as follows:


		Lease Acres
		Expiring

		Gross		Net

Year ending:
December 31, 2005			29,865		5,711
December 31, 2006			16,281		3,693
December 31, 2007 and later			39,689		8,924

	Total		85,835		18,328

Drilling Activities — The results of our participation in the drilling of developmental and exploratory wells during 2004, 2003 and 2002 follows:


	Developmental Wells								Exploratory Wells

	Productive				Dry Holes				Productive				Dry Holes

	Gross		Net		Gross		Net		Gross		Net		Gross		Net

Year ending:
December 31, 2004		22		4.55		—		—		10		2.01		6		1.71
December 31, 2003		27		4.58		11		2.52		12		1.99		4		0.88
December 31, 2002		24		4.17		11		2.67		6		0.56		1		0.25

In addition, we were participating in nine wells, 1.92 net, that were being drilled at December 31, 2004.

Generally, a developmental well is a well that is drilled into an oil and natural gas reservoir that is known to be productive. An exploratory well is a well that is drilled to find oil and natural gas in an unproved area.

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 2004, 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 6,800 full-time persons (300 office personnel and 6,500 field personnel) at December 31, 2004. 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 “Forward Looking Statements and Cautionary Statements for Purposes of the ’Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995,” beginning on page 14 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 Items 1 and 2.

Corporate Headquarters, Field Offices and Other Facilities

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 34,000 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,

	•	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,

	•	Wyoming, and

	•	Tennessee.

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 services 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.*

We are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition.


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

None.

FORWARD LOOKING STATEMENTS AND CAUTIONARY

STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS

OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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 $5.45 in 2003 and $5.95 in 2004 resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 188 in 2003 and to 211 in 2004. 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 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 many downturns in demand over the last several years. 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.

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. 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.

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

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
2003:
First quarter	$	17.75	$	13.55
Second quarter		18.49		15.90
Third quarter		16.14		12.58
Fourth quarter		16.97		12.84


*(b)*	*Holders*

As of January 24, 2005, there were approximately 940 holders of record and approximately 48,000 beneficial holders of our common shares.


*(c)*	*Dividends and Buyback Program*

No dividend was declared or paid in 2003. 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 form $0.02 per share. The next quarterly cash dividend is to be paid to holders of record on February 28, 2005 and paid on March 4, 2005. 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 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 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. 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. We did not repurchase any of our shares in the fourth quarter of 2004.


*(d)*	*Securities Authorized for Issuance Under Equity Compensation Plans*

Equity compensation to our employees, officers and directors as of December 31, 2004 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

8,635,720

12.64

3,482,992

(1)

Equity compensation plans not approved by security holders(2)

1,370,322

9.74

78,161

Total

10,006,042

12.24

3,561,153


(1)	The Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended, allows for the grant of restricted shares and performance awards, in addition to stock options and stock appreciation rights, to key employees, officers and directors, which are subject to certain vesting and forfeiture provisions. Of the securities remaining available for future issuance under equity compensation plans approved by security holders in column (c), there are 2,997,992 securities available under this plan.

(2)	The Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan was approved by the Board of Directors in July 2001. The terms of the Plan provide 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 may be awarded under the Plan. 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.

	In July 2001, the Board of Directors approved option grants, not included in any of the stock option plans, for two non-employee directors. Each of the two non-employee directors was granted an option to purchase 24,000 shares of our common stock at an exercise price greater than the fair market value of our common stock on the grant date. The options vested in November 2001 and expire in November 2005. As of December 31, 2004, one of these options to purchase 24,000 shares of our common stock was outstanding.


Item 6.	*Selected Financial Data.*

Our selected consolidated financial data as of December 31, 2004, 2003, 2002, 2001 and 2000, 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, has been restated to provide for (i) the retroactive effect of the merger with UTI Energy Corp., on May 8, 2001; (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. Certain reclassifications have been made to the historical financial data to conform with the 2004 presentation.


			Years Ended December 31,

			2004			2003			2002			2001			2000

			(In thousands)
Income Statement Data:
Operating revenues:
	Contract drilling		$	809,691		$	639,694		$	410,295		$	839,931		$	512,998
	Pressure pumping			66,654			46,083			32,996			39,600			21,465
	Drilling and completion fluids			90,557			69,230			69,943			94,456			32,053
	Oil and natural gas			33,867			21,163			14,723			15,988			15,806

		Total		1,000,769			776,170			527,957			989,975			582,322

Operating costs and expenses:
	Contract drilling			556,869			475,224			318,201			487,343			384,840
	Pressure pumping			37,561			26,184			19,802			21,146			13,403
	Drilling and completion fluids			76,503			61,424			60,762			80,034			26,545
	Oil and natural gas			7,978			4,808			3,956			5,190			4,872
	Depreciation, depletion, amortization and impairment			119,395			97,998			91,216			86,159			61,464
	General and administrative			32,007			27,709			26,140			28,561			22,190
	Bad debt expense			897			259			320			2,045			570
	Merger costs			—			—			—			5,943			—
	Restructuring and other charges			—			(2,452	)		4,700			7,202			—
	Other			(1,655	)		(2,174	)		(538	)		(820	)		(147	)

		Total		829,555			688,980			524,559			722,803			513,737

Operating income				171,214			87,190			3,398			267,172			68,585

Other income (expense)				680			2,694			803			(677	)		(8,481	)
Income before income taxes and cumulative effect of change in accounting principle				171,894			89,884			4,201			266,495			60,104
Income tax expense				63,161			32,996			1,827			102,333			22,878

Income before cumulative effect of change in accounting principle				108,733			56,888			2,374			164,162			37,226
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287				—			(469	)		—			—			—

Net income			$	108,733		$	56,419		$	2,374		$	164,162		$	37,226


			Years Ended December 31,

			2004		2003		2002		2001		2000

					(In thousands, except per share amounts)
Net income per common share:
	Basic:
		Income before cumulative effect of change in accounting principle	$	0.65	$	0.35	$	0.02	$	1.07	$	0.26

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

		Net income	$	0.65	$	0.35	$	0.02	$	1.07	$	0.26

	Diluted:
		Income before cumulative effect of change in accounting principle	$	0.64	$	0.35	$	0.01	$	1.04	$	0.25

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

		Net income	$	0.64	$	0.34	$	0.01	$	1.04	$	0.25

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

Weighted average number of common shares outstanding:
	Basic			166,258		161,272		157,410		152,814		142,414

	Diluted			169,211		164,572		162,504		158,394		149,682

Balance Sheet Data:
Total assets			$	1,322,911	$	1,084,114	$	942,823	$	869,642	$	739,898
Long-term debt				—		—		—		—		79,416
Stockholders’ equity				1,007,539		819,749		737,731		687,142		481,299
Working capital				236,957		199,613		167,863		110,172		127,299


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.

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, 2004, our operating revenues consisted of the following (dollars in thousands):


	2004				2003				2002

Contract drilling	$	809,691	81	%	$	639,694	82	%	$	410,295	78	%
Pressure pumping		66,654	7			46,083	6			32,996	6
Drilling and completion fluids		90,557	9			69,230	9			69,943	13
Oil and natural gas		33,867	3			21,163	3			14,723	3

	$	1,000,769	100	%	$	776,170	100	%	$	527,957	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 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 Texas, 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 361 rigs as of December 31, 2004. 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 2004, our average number of rigs operating increased to 211 from 188 in 2003 and our average revenue per operating day increased to $10,470 from $9,300 in 2003. Primarily due to these improved operating results, we experienced an increase of approximately $52 million in consolidated net income in 2004.

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 in our “Forward Looking Statements and Cautionary Statements for Purposes of the ’Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” contained on page 14 of this Report.

Management believes that the liquidity of our balance sheet as of December 31, 2004, which includes approximately $237.0 million in working capital (including $112 million in cash), no long term debt and a $200 million line of credit with availability of $151 million (net of outstanding letters of credit totaling $49 million) provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our property and equipment and survive downturns in our industry.

Commitments and Contingencies — We have no commitments or contingencies which require disclosure in our financial statements other than letters of credit of approximately $49 million at December 31, 2004, maintained 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. No amounts have been drawn under the letters of credit.

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.

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 and Western Canada. As of December 31, 2004, we owned 361 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 Texas, South Texas, Southeastern New Mexico, Utah and Mississippi.

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 2004, 2003 or 2002.

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 $3.2 million, $1.4 million and $700,000 for the years ended December 31, 2004, 2003 and 2002, respectively, is included in depreciation, depletion, amortization 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. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2004, was based on the segment’s improved operating results in 2004 and on our expectations that these improved results will continue. If the improved results do not continue, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired.

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, depletion, and amortization,

	•	asset impairment,

	•	reserves for self-insured levels of insurance coverages, and

	•	fair values of assets and liabilities assumed.

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, 2004, affiliated persons were working interest owners in 237 of 300 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 2004 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, 2004. These activities resulted in a payable to the affiliated persons of approximately $1.2 million and $871,000 and a receivable from the affiliated persons of approximately $856,000 and $888,000 at December 31, 2004 and 2003, respectively.


			Year Ended
			December 31, 2004

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

Cloyce A. Talbott			$	186,971	$	42,313
Anita Talbott(3)				76,423		22,591
Jana Talbott, Executrix to the Estate of Steve Talbott(3)				11,655		2,940
Stan Talbott(3)				9,320		4,366
John Evan Talbott Trust(3)				3,124		668
Lisa Beck and Stacy Talbott(3)				978,607		410,334
SSI Oil & Gas, Inc.(4)				163,584		263,123
IDC Enterprises, Ltd.(5)				12,019,230		6,462,580

	Subtotal			13,448,914		7,208,915

A. Glenn Patterson				123,583		27,468
Robert Patterson(6)				8,476		2,518
Thomas M. Patterson(6)				8,476		2,518

	Subtotal			140,535		32,504

Jonathan D. Nelson, Chief Financial Officer				248,297		263,549

		Total	$	13,837,746	$	7,504,968


(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 2004, 2003 and 2002, we paid approximately $914,000, $740,000 and $279,000, respectively, to TMP Truck and Trailer LP (“TMP”), an entity 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 2004 and 2003, we paid approximately $39,000 and $209,000, respectively, to Melco Services (“Melco”) for dirt contracting services and $44,000 and $59,000, 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.

Liquidity and Capital Resources

As of December 31, 2004, we had working capital of $237.0 million including cash and cash equivalents of $112.4 million. For 2004, our sources of cash flow included:


	•	$222.3 million from operations,

	•	$24.5 million from the exercise of stock options and warrants, and

	•	$3.3 million from the sale of property and equipment.

We used approximately $224.1 million:


	•	to make capital expenditures for the betterment and refurbishment of our drilling rigs,

	•	for the acquisition and procurement of drilling equipment,

	•	to fund capital expenditures for our pressure pumping and drilling and completion fluids divisions, and

	•	to fund leasehold acquisition and development and exploration of oil and natural gas properties.

Additionally, $10.0 million was used to pay quarterly dividends on our common stock, $1.5 million was used to buy 100,000 shares of our common stock pursuant to the stock buyback program authorized by our Board of Directors on June 7, 2004 and issuance costs of $780,000 were incurred during 2004 relating to our new $200 million credit facility. As of December 31, 2004, $1.8 million 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 February 2004, we completed the acquisition of TMBR in which one of our 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 our 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.

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, 2004). 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 $49 million at December 31, 2004. There were no outstanding borrowings under the LOC at December 31, 2004. We incurred approximately $445,000 in costs to terminate the previous $100 million credit facility. These costs were expensed in 2004.

In December 2004, we entered into an agreement to acquire the U.S. land drilling assets of Key Energy Services, Inc. for approximately $62 million. The assets include 25 active and 10 stacked land-based drilling rigs, related drilling equipment, four yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. This transaction was completed in January 2005 using approximately $62 million of cash.

In February 2005, our 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. The next quarterly cash dividend is to be paid to holders of record on February 28, 2005 and paid on March 4, 2005.

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, 2004 and 2003*

A summary of operations by business segment for the years ended December 31, 2004 and 2003 follows:


	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	$	4,441		$	4,425			0.4	%
Depreciation	$	98,334		$	84,379			16.5	%
Operating income	$	150,047		$	75,666			98.3	%
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	$	157,916		$	95,175			65.9	%

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,

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	$	2,196	$	2,319			(5.3	)%
Operating income (loss)	$	4,162	$	(1,960	)		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,

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			—	%
Restructuring and other charges	$	—	$	(2,452	)		N/A
Other income from operations	$	1,655	$	2,174			(23.9	)%
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. 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.


	*Comparison of the years ended December 31, 2003 and 2002*

Operations by business segment for the years ended December 31, 2003 and 2002 follow:


	Years Ended December 31,

Contract Drilling	2003			2002			% Change

	(Dollars in thousands)
Revenues	$	639,694		$	410,295			55.9	%
Direct operating costs	$	475,224		$	318,201			49.3	%
Selling, general and administrative	$	4,425		$	3,987			11.0	%
Depreciation and amortization	$	84,379		$	80,500			4.8	%
Operating income	$	75,666		$	7,607			894.7	%
Operating days		68,798			45,919			49.8	%
Average revenue per operating day	$	9.30		$	8.94			4.0	%
Average direct operating costs per operating day	$	6.91		$	6.93			(0.3	)%
Number of owned rigs at end of period		343			324			5.9	%
Average number of rigs owned during period		336			323			4.0	%
Average rigs operating		188			126			49.2	%
Rig utilization percentage		56	%		39	%		43.6	%
Capital expenditures	$	95,175		$	68,516			38.9	%

The average market price of natural gas and our average rigs operating for each of the fiscal quarters in 2003 and 2002 follow:


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

2003:
Average natural gas price	$	5.91	$	5.70	$	4.88	$	5.29
Average rigs operating		176		195		192		191
2002:
Average natural gas price	$	2.51	$	3.41	$	3.20	$	4.31
Average rigs operating		117		119		127		140

The average market price of natural gas improved to $5.45 per Mcf in 2003 compared to $3.36 per Mcf in 2002, resulting in an increase in demand for our contract drilling services. Our average number of rigs operating increased to 188 in 2003 from 126 in 2002.

Revenues and direct operating costs increased as a result of the increased number of operating days in 2003. Revenue per operating day increased as a result of increased demand for our services which resulted in additional increases in revenues and operating income. As a result of the increased utilization of our drilling rigs in 2003, significant capital expenditures were incurred to modify and upgrade our existing drilling rigs and

to acquire additional related equipment to meet the increased demand. Increased depreciation expense in 2003 resulted from this increased level of capital spending, as well as acquisitions.


	Years Ended December 31,

Pressure Pumping	2003		2002		% Change

	(Dollars in thousands)
Revenues	$	46,083	$	32,996		39.7	%
Direct operating costs	$	26,184	$	19,802		32.2	%
Selling, general and administrative	$	5,683	$	4,301		32.1	%
Depreciation	$	3,774	$	2,803		34.6	%
Operating income	$	10,442	$	6,090		71.5	%
Total jobs		5,667		3,796		49.3	%
Average revenue per job	$	8.13	$	8.69		(6.4	)%
Average direct operating costs per job	$	4.62	$	5.22		(11.5	)%
Capital expenditures	$	10,524	$	7,399		42.2	%

The increases in revenues and expenses for our pressure pumping operations were attributable to improved industry conditions, as discussed in “Contract Drilling” above, and continued expansion of our pressure pumping services into the Appalachian regions of Kentucky and West Virginia. This expansion also resulted in increases in selling, general and administrative expenses and depreciation in 2003 compared to 2002.


	Years Ended December 31,

Drilling and Completion Fluids	2003			2002			% Change

	(Dollars in thousands)
Revenues	$	69,230		$	69,943			(1.0	)%
Direct operating costs	$	61,424		$	60,762			1.1	%
Selling, general and administrative	$	7,447		$	7,243			2.8	%
Depreciation and amortization	$	2,319		$	2,216			4.6	%
Operating loss	$	(1,960	)	$	(278	)		605.0	%
Total jobs		1,931			1,457			32.5	%
Average revenue per job	$	35.85		$	48.00			(25.3	)%
Average direct operating costs per job	$	31.81		$	41.70			(23.7	)%
Capital expenditures	$	912		$	1,571			(41.9	)%

The decrease in revenues was primarily due to the decrease in larger jobs completed in the Gulf of Mexico as activity in the Gulf of Mexico continued to be slow despite improved natural gas prices in 2003. The decrease in revenues from the Gulf of Mexico was largely offset by increased demand for our land-based drilling and completion fluids services. Land-based drilling and completion fluids jobs typically generate less revenue per job than offshore jobs. As a result, our average revenue per job decreased in 2003 compared to 2002.


	Years Ended December 31,

Oil and Natural Gas Production and Exploration	2003		2002		% Change

	(Dollars in thousands)
Revenues	$	21,163	$	14,723		43.7	%
Direct operating costs	$	4,808	$	3,956		21.5	%
Selling, general and administrative	$	1,489	$	1,571		(5.2	)%
Depreciation and depletion	$	7,082	$	5,251		34.9	%
Operating income	$	7,784	$	3,945		97.3	%
Capital expenditures	$	10,015	$	6,357		57.5	%
Average net daily oil production (Bbls)		788		794		(0.8	)%
Average net daily gas production (Mcf)		5,656		5,109		10.7	%
Average oil sales price (per Bbl)	$	30.54	$	25.02		22.1	%
Average gas sales price (per Mcf)	$	4.97	$	2.91		70.8	%

Increased revenues and operating income are primarily attributable to increased prices received from sales of oil and natural gas and increased production of natural gas in 2003. Depreciation and depletion expense primarily increased as a result of increased production of natural gas in 2003 as compared to 2002, as well as an increase of approximately $700,000 associated with expenses incurred to partially impair certain oil and natural gas properties.


	Years Ended December 31,

Corporate and Other	2003			2002		% Change

	(Dollars in thousands)
Selling, general and administrative	$	8,665		$	9,038		(4.1	)%
Bad debt expense	$	259		$	320		(19.1	)%
Depreciation	$	444		$	446		(0.4	)%
Restructuring and other charges	$	(2,452	)	$	4,700		N/A
Other income from operations	$	2,174		$	538		304.1	%
Interest income	$	1,116		$	1,110		0.5	%
Interest expense	$	292		$	532		(45.1	)%

In 2003, Restructuring and other charges reflects a payment received in the first quarter of 2003 of approximately $2.5 million as settlement for contract drilling services previously provided in Mexico by Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary. The underlying accounts receivable balance had been reserved as uncollectible at the time of our acquisition of Norton Drilling Company Mexico, Inc. in 1999. In 2002, Restructuring and other charges reflects a $4.7 million charge due to the financial failure of a workers’ compensation insurance carrier we used from 1992 until March 2001.

Income Taxes


	Years Ended December 31,

	2004			2003			2002

	(Dollars in thousands)
Income before income tax	$	171,894		$	89,884		$	4,201
Income tax expense		63,161			32,996			1,827
Effective tax rate		36.7	%		36.7	%		43.5	%

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. The significance of the impact of the permanent differences of approximately 6% to our effective income tax rate in 2002 was largely attributable to our reduced 2002 pretax earnings.

For tax purposes, we have available at December 31, 2004, Federal net operating loss carryforwards of approximately $16 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: 2005 — $5 million, 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 non-cash 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 $23.5 million, $17.9 million and $23.7 million for 2004, 2003 and 2002, 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 $5.45 in 2003 and $5.95 in 2004, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 188 in 2003 and 211 in 2004. 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.

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 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 . This statement is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. We will adopt SFAS 123(R) no later than our fiscal quarter beginning July 1, 2005.

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 will expense stock options using the Modified Prospective Transition method as described in SFAS 123(R). This method requires expense to be recognized for new grants or modifications to existing grants issued in the period of adoption, plus the current period expense for non-vested awards issued prior to the adoption of SFAS 123(R). Compensation cost for the unvested stock-based awards will be recognized over the remaining vesting period. 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 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 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.


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 over 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 when they are translated to U.S. dollars. Also, the value of our Canadian net assets in U.S. dollars may decline.


Item 8.	*Financial Statements and Supplementary Data.*

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


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

None.


Item 9A.	*Controls and Procedures.*

Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934) was evaluated by our management, with the participation of our Chief Executive Officer, Cloyce A. Talbott (principal executive officer), and our Vice President, Chief Financial Officer, Secretary and Treasurer, Jonathan D. Nelson (principal financial and accounting officer). Messrs. Talbott and Nelson have concluded that our disclosure controls and procedures are effective, as of the end of the period covered by this Report, to help ensure that information we are required to disclose in reports that we file with the SEC is accumulated and communicated to management and recorded, processed, summarized and reported within the time periods prescribed by the SEC.

There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter (the quarter ended December 31, 2004) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is 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.

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 management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2004, our internal control over financial reporting is effective based on those criteria.

Our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, the independent registered public accounting firm who also audited our consolidated financial statements as stated in their report which appears on page F-2 of this Report on Form 10-K.


Item 9B.	Other Information

On October 22, 2004, we entered into a written letter agreement with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III confirming and evidencing the existing agreement between us and each of Messrs. Siegel, Berns and Vollmer pursuant to which we have agreed to pay each such person within ten (10) days of the termination of his employment with us for any reason (including voluntary termination by them), an amount in cash equal to his annual base salary at the time of such termination. Any such payment made by us pursuant to the agreement evidenced in the letter agreement will reduce dollar for dollar any payment owed to such person, if any, pursuant to the Change in Control Agreement dated January 29, 2004 between the Company and such person or any agreement in substitution therefor.

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.


2	.1	Asset Purchase Agreement among Key Energy Drilling, Inc., Key Energy Drilling Beneficial, L.P., Key Rocky Mountain, Inc., Key Four Corners, Inc. and Key Energy Services, Inc. and Patterson-UTI Drilling Company LP, LLLP and Patterson-UTI Energy, Inc., dated as of December 7, 2004.

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 2.1, 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	Stock Option Agreement dated July 20, 2001 between Patterson-UTI Energy, Inc. and Kenneth R. Peak (filed March 19, 2002 as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 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 Jonathan D. Nelson (filed August 9, 2004 as Exhibit 10.5 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	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	.17	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	.18	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	.19	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	.20	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	.21	Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (filed on February 4, 2004 as Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*



10	.22	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	.23	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.*

10	.24	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, Jonathan D. Nelson 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	.25	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	.26	Summary Description of 2003 Cash Bonus Plan.*

10	.27	Summary Description of Director Compensation.*

14	.1	Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (filed 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.

23	.2	Consent of Independent Petroleum Engineer — M. Brian Wallace, P.E.

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, 2004 and 2003		F-4
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002		F-5
Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002		F-6
Consolidated Statements of Changes In Cash Flows for the years ended December 31, 2004, 2003 and 2002		F-7
Notes to Consolidated Financial Statements		F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Patterson-UTI Energy, Inc.

We have completed an integrated audit of Patterson-UTI Energy, Inc’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31 , 2004 and audits of its 2003 and 2002 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule on page S-1 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.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the 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 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

F-2

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.


	PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2005

F-3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


				December 31,

				2004			2003

				(In thousands, except share
				data)
ASSETS
Current assets:
	Cash and cash equivalents			$	112,371		$	100,483
	Accounts receivable, net of allowance for doubtful accounts of $1,909 and $2,133 at December 31, 2004 and 2003, respectively				214,097			156,345
	Federal and state income taxes receivable				—			12,667
	Inventory				17,738			15,206
	Deferred tax assets, net				15,991			16,449
	Other				26,836			15,697

			Total current assets		387,033			316,847
Property and equipment, at cost, net					828,875			693,631
Goodwill					101,326			51,179
Investment in equity securities					—			19,771
Other					5,677			2,686

			Total assets	$	1,322,911		$	1,084,114


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable:
		Trade		$	54,553		$	41,093
		Accrued revenue distributions			11,297			8,545
		Other			2,309			6,743
	Accrued Federal and state income taxes payable				2,754			—
	Accrued expenses				79,163			60,853

			Total current liabilities		150,076			117,234
Deferred tax liabilities, net					162,040			143,309
Other					3,256			3,822

			Total liabilities		315,372			264,365

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 at December 31, 2004 and 200,000,000 shares at December 31, 2003 with 171,625,841 (affected by a two- for-one stock split) and 82,483,148 issued and 168,512,745 (affected by a two-for-one stock split) and 80,976,600 outstanding at December 31, 2004 and 2003, respectively				1,716			825
	Additional paid-in capital				597,280			506,018
	Deferred compensation				(5,420	)		—
	Retained earnings				415,489			317,627
	Accumulated other comprehensive income, net of tax				11,611			6,934
	Treasury stock, at cost, 3,113,096 shares (affected by a two-for-one stock split) and 1,506,548 shares at December 31, 2004 and 2003, respectively				(13,137	)		(11,655	)

			Total stockholders’ equity		1,007,539			819,749

			Total liabilities and stockholders’ equity	$	1,322,911		$	1,084,114

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

F-4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


			Years Ended December 31,

			2004			2003			2002

			(In thousand, except per share data)
Operating revenues:
	Contract drilling		$	809,691		$	639,694		$	410,295
	Pressure pumping			66,654			46,083			32,996
	Drilling and completion fluids			90,557			69,230			69,943
	Oil and natural gas			33,867			21,163			14,723

				1,000,769			776,170			527,957

Operating costs and expenses:
	Contract drilling			556,869			475,224			318,201
	Pressure pumping			37,561			26,184			19,802
	Drilling and completion fluids			76,503			61,424			60,762
	Oil and natural gas			7,978			4,808			3,956
	Depreciation, depletion, amortization and impairment			119,395			97,998			91,216
	General and administrative			32,007			27,709			26,140
	Bad debt expense			897			259			320
	Restructuring and other charges			—			(2,452	)		4,700
	Gain on sale of assets			(1,655	)		(2,174	)		(538	)

				829,555			688,980			524,559

Operating income				171,214			87,190			3,398

Other income (expense):
	Interest income			1,140			1,116			1,110
	Interest expense			(695	)		(292	)		(532	)
	Other			235			1,870			225

				680			2,694			803

Income before income taxes and cumulative effect of change in accounting principle				171,894			89,884			4,201

Income tax expense (benefit):
	Current			39,688			15,088			(21,878	)
	Deferred			23,473			17,908			23,705

				63,161			32,996			1,827

Income before cumulative effect of change in accounting principle				108,733			56,888			2,374
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287				—			(469	)		—

Net income			$	108,733		$	56,419		$	2,374

Net income per common share:
	Basic:
		Income before cumulative effect of change in accounting principle	$	0.65		$	0.35		$	0.02

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

		Net income	$	0.65		$	0.35		$	0.02

	Diluted:
		Income before cumulative effect of change in accounting principle	$	0.64		$	0.35		$	0.01

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

		Net income	$	0.64		$	0.34		$	0.01

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

		Diluted		169,211			164,572			162,504

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

F-5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY


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

		(In thousands)
December 31, 2001			78,463	$	784	$	441,475	$	—		$	258,834		$	(2,296	)	$	(11,655	)	$	687,142
	Issuance of common stock		650		7		16,933		—			—			—			—			16,940
	Exercise of stock options and warrants		2,464		25		15,714		—			—			—			—			15,739
	Tax benefit related to exercise of stock options		—		—		15,079		—			—			—			—			15,079
	Foreign currency translation, net of tax		—		—		—		—			—			457			—			457
	Net income		—		—		—		—			2,374			—			—			2,374

December 31, 2002			81,577		816		489,201		—			261,208			(1,839	)		(11,655	)		737,731
	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, net of tax		—		—		—		—			—			8,773			—			8,773
	Net income		—		—		—		—			56,419			—			—			56,419

December 31, 2003			82,483		825		506,018		—			317,627			6,934			(11,655	)		819,749
	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, net of tax		—		—		—		—			—			4,677			—			4,677
	Purchase of treasury stock		—		—		—		—			—			—			(1,482	)		(1,482	)
	Payment of cash dividend (See Note 11)		—		—		—		—			(10,021	)		—			—			(10,021	)
	Effect of two-for-one stock split (See Note 11)		84,986		850		—		—			(850	)		—			—			—
	Net income		—		—		—		—			108,733			—			—			108,733

December 31, 2004			171,626	$	1,716	$	597,280	$	(5,420	)	$	415,489		$	11,611		$	(13,137	)	$	1,007,539

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 CASH FLOWS


				Years Ended December 31,

				2004			2003			2002

				(In thousands)
Cash flows from operating activities:
	Net income			$	108,733		$	56,419		$	2,374
	Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion, amortization and impairment				119,395			97,998			91,216
	Provision for bad debts				897			259			320
	Deferred income tax expense				23,473			17,908			23,705
	Tax benefit related to exercise of stock options				10,666			6,540			15,079
	Amortization of deferred compensation expense				1,222			—			—
	Gain on sale of assets				(1,655	)		(2,174	)		(538	)
	Cumulative effect of change in accounting principle, net of tax				—			(469	)		—
		Changes in operating assets and liabilities, net of business acquired:
			Accounts receivable		(50,682	)		(55,791	)		34,565
			Federal income taxes receivable		15,470			10,919			(23,216	)
			Inventory and other current assets		(13,556	)		(8,984	)		(222	)
			Accounts payable		12,861			12,322			(11,079	)
			Accrued expenses		1,555			22,814			(771	)
			Other liabilities		(6,090	)		5,015			362

		Net cash provided by operating activities			222,289			162,776			131,795

Cash flows from investing activities:
	Acquisitions, net of cash acquired				(32,514	)		(40,832	)		—
	Purchases of property and equipment				(191,560	)		(116,626	)		(83,843	)
	Proceeds from sales of property and equipment				3,303			4,548			1,813
	Purchase of investment equity securities				—			—			(17,659	)
	Change in other assets				(1,766	)		(1,693	)		735

		Net cash used in investing activities			(222,537	)		(154,603	)		(98,954	)

Cash flows from financing activities:
	Purchase of treasury stock				(1,482	)		—			—
	Dividends paid				(10,021	)		—			—
	Line of credit issuance costs				(780	)		—			—
	Proceeds from exercise of stock options and warrants				24,519			10,286			15,739

		Net cash provided by financing activities			12,236			10,286			15,739

		Effect of foreign exchange rate changes on cash			(100	)		(130	)		(10	)

			Net increase in cash and cash equivalents		11,888			18,329			48,570
Cash and cash equivalents at beginning of year					100,483			82,154			33,584

Cash and cash equivalents at end of year				$	112,371		$	100,483		$	82,154

Supplemental disclosure of cash flow information:
	Net cash received (paid) during the year for:
			Interest	$	(245	)	$	(292	)	$	(532	)
			Income taxes		(12,500	)		2,730			13,492

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 — (Continued)

Non-cash investing and financing activities:

In February 2004, the Company completed its acquisition of TMBR/ Sharp Drilling, Inc. (“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 2).

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 and Western Canada. As of December 31, 2004, the Company owned 361 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 in Texas, Southeastern New Mexico, Oklahoma, the Gulf Coast region of Louisiana and the Gulf of Mexico. 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 Texas, South Texas, Southeastern New Mexico, Utah and Mississippi.

Basis of presentation — As a result of the Company increasing its ownership of 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 to provide for the retroactive application of the equity method of accounting for the Company’s investment in TMBR (see Note 6).

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. The December 31, 2003 balance sheet was not restated as a result of this transaction; however, 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, 2002.


	*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.

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.

F-9

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 determines the allowance based on historical write-off experience. 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

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 determinations are made. Costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. The Company reviews wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, the Company considers the costs of the well to be impaired and recognizes the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. The capitalized costs of both developmental 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.

F-10

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. As such, the Company assess 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. With respect to the Company’s drilling and completion fluids business, the determination that no impairment existed as of December 31, 2004, was based on the segment’s improved operating results in 2004 and on the Company’s expectations that these improved results will continue. If the improved results do not continue, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired.

The following table summarizes depreciation, depletion, amortization and impairment expense for 2004, 2003 and 2002 (in millions):


		2004		2003		2002

Depreciation expense		$	106.0	$	90.9	$	85.8
Depletion expense			10.1		5.6		4.4
Amortization expense			0.1		0.1		0.3
Impairment of oil and natural gas properties			3.2		1.4		0.7

	Total	$	119.4	$	98.0	$	91.2

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, 2004, 2003 and 2002, dilutive securities, consisting of certain stock options and warrants, (See Note 12) included in the calculation of Diluted EPS were 3.0 million shares, 3.3 million shares and 5.1 million shares, respectively. At December 31, 2004, 2003 and 2002, there were potentially dilutive securities of 640,000, 1.9 million and 657,000, 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 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.

F-11

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock based compensation — At December 31, 2004, the Company had seven stock-based employee compensation plans, of which three were active. The Company accounts for those plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”) and related interpretations. During the second quarter of 2004, 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. 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. Compensation expense of $773,000, net of tax, was included in net income for the twelve months ended December 31, 2004. Other than the Restricted Shares discussed above, no additional stock-based employee compensation cost is reflected in net income, as all options granted under the plans discussed above had an exercise price equal to or in excess of 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 (“FASB”) Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” (“SFAS 123”) to stock-based employee compensation (in thousands, except per share amounts):


		Years Ended December 31,

		2004			2003			2002

Net income, as reported		$	108,733		$	56,419		$	2,374
Add: Stock-based employee compensation expense recorded, net of tax			773			—			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects(1)			(11,531	)		(10,506	)		(5,296	)

Pro forma net income (loss)		$	97,975		$	45,913		$	(2,922	)

Earnings (loss) per share:
	Basic, as reported	$	0.65		$	0.35		$	0.02

	Basic, pro forma	$	0.59		$	0.28		$	(0.02	)

	Diluted, as reported	$	0.64		$	0.34		$	0.01

	Diluted, pro forma	$	0.59		$	0.28		$	(0.02	)

Weighted-average fair value per share of options granted(1)		$	6.25		$	5.59		$	7.60


(1)	See Note 12 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.

Recently Issued Accounting Standards — The FASB issued Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”) in December 2004; it replaces SFAS 123, and supersedes APB 25. This statement is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company will adopt SFAS 123(R) no later than its fiscal quarter beginning July 1, 2005.

The Company currently uses the intrinsic value method to value stock options, and accordingly, no compensation expense has been recognized for stock options since the Company grants stock options with exercise prices equal to the Company’s common stock market price on the date of the grant. SFAS 123(R)

F-12

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

requires the expensing of all stock-based compensation, including stock options and restricted shares, using the fair value method. The Company will expense stock options using the Modified Prospective Transition method as described in SFAS 123(R). This method requires expense to be recognized for new grants or modifications to existing grants issued in the period of adoption, plus the current period expense for non-vested awards issued prior to the adoption of SFAS 123(R). Compensation cost for the unvested stock-based awards will be recognized over the remaining vesting period. No expense will be recognized for stock options vested in periods prior to the adoption of SFAS 123(R).

The Company is evaluating the impact of its adoption of SFAS 123(R) on its results of operations and financial position. Adoption is not expected to have a material effect on the Company’s 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”). SFAS 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 the Company’s financial position or results of operations.

Reclassifications — Certain reclassifications have been made to the 2003 and 2002 consolidated financial statements in order for them to conform with the 2004 presentation.


2.	Acquisitions

Key Energy Services, Inc. — In December 2004, the Company entered into an agreement to acquire the U.S. land-based drilling assets of Key Energy Services, Inc. for approximately $62 million. The assets include 25 active and 10 stacked drilling rigs, related drilling equipment, four yard facilities and a rig moving fleet consisting of approximately 45 trucks and 100 trailers. This transaction was completed in January 2005 using approximately $62 million of cash.


	*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 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.

F-13

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The purchase price was calculated as follows (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			12,638
Less: Cash acquired			(7,909	)

	Total purchase price	$	114,399

The purchase price was allocated among assets acquired and liabilities assumed based on their estimated fair market values as follows (in thousands):


Current assets		$	7,181
Fixed assets			60,784
Other long term assets			172
Deferred tax assets			13,080
Goodwill			50,147
Current liabilities			(7,080	)
Other long term liabilities			(1,090	)
Deferred tax liability			(8,795	)

	Total purchase allocation	$	114,399

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):


		2004		2003

Revenue		$	1,005,357	$	818,774
Income before cumulative effect of change in accounting principle			108,434		58,598
Net income			108,434		58,193
Earnings per share:
	Basic	$	0.65	$	0.36

	Diluted	$	0.64	$	0.35


	*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.

F-14

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.


	*2002 Acquisition*

Odin Drilling, Inc. — On March 21, 2002, the Company acquired five SCR electric land-based drilling rigs through the acquisition of Odin Drilling, Inc., for a purchase price of $16.9 million. The purchase price consisted of 1.3 million shares of common stock valued at $13.03 per share (adjusted to reflect the two-for-one stock split on June 30, 2004). A deferred tax liability of $4.1 million was recorded as a result of the transaction. 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.


3.	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, 2004, 2003 and 2002 (in thousands):


	2004		2003		2002

Net income	$	108,733	$	56,419	$	2,374
Other comprehensive income:
Foreign currency translation adjustment related to Canadian operations, net of tax		4,677		8,773		457

Comprehensive income	$	113,410	$	65,192	$	2,831

F-15

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	Property and Equipment

Property and equipment consisted of the following at December 31, 2004 and 2003 (in thousands):


	2004			2003

Drilling rigs and related equipment	$	1,217,497		$	1,022,795
Other equipment		83,683			65,659
Oil and natural gas properties		82,711			57,625
Buildings		13,008			11,773
Land		3,949			3,684

		1,400,848			1,161,536
Less accumulated depreciation and depletion		(571,973	)		(467,905	)

	$	828,875		$	693,631


5.	Goodwill

Goodwill is evaluated to determine if the fair value of the asset has decreased below its carrying value. At December 31, 2004 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. With respect to the Company’s drilling and completion fluids business, the determination that no impairment existed as of December 31, 2004 was based on the segment’s improved operating results in 2004 and on the Company’s expectations that these improved results will continue. If the improved results do not continue, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired. Goodwill as of December 31, 2004 and 2003 are as follows (in thousands):


					2004		2003

Drilling:
	Goodwill at beginning of period				$	41,215	$	41,215
		Goodwill in TMBR				50,147		—

			Goodwill at end of period			91,362		41,215

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	$	101,326	$	51,179


6.	Investment in Equity Securities

As a result of the Company increasing its ownership of 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 to provide for the retroactive application of the equity method of accounting for the Company’s investment in TMBR.

F-16

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the restated balances as of December 31, 2003, and for the twelve months ended December 31, 2003 and 2002 using the equity method of accounting for its investment in TMBR (in thousands, except share amounts):


		Previously
		Reported		Restated

Balance Sheet as of December 31, 2003:
	Investment in equity securities	$	20,274	$	19,771
	Accumulated other comprehensive income, net of tax		8,554		6,934
	Deferred tax liability		143,490		143,309
	Retained earnings		316,329		317,627


			Twelve Months Ended				Twelve Months Ended
			December 31, 2003				December 31, 2002

			Previously				Previously
			Reported		Restated		Reported			Restated

Comprehensive Income
	Comprehensive income, net of tax		$	65,689	$	65,192	$	2,656		$	2,831
Income Statement
	Other income			143		1,870		(137	)		225
	Deferred income tax expense			17,274		17,908		23,548			23,705
	Net income			55,326		56,419		2,169			2,374
	Net income per common share:
		Basic	$	0.34	$	0.35	$	0.01		$	0.02

		Diluted	$	0.34	$	0.34	$	0.01		$	0.01


7.	Accrued Expenses

Accrued expenses consisted of the following at December 31, 2004 and 2003 (in thousands):


	2004		2003

Salaries, wages, payroll taxes and benefits	$	21,245	$	15,772
Workers’ compensation liability		38,677		31,646
Sales, use and other taxes		5,863		5,809
Insurance, other than workers’ compensation		7,061		1,848
Other		6,317		5,778

	$	79,163	$	60,853

F-17

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


8.	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 Company recorded a liability of approximately $1.1 million in the first quarter of 2003 upon initial adoption of SFAS 143. The following table describes the changes to the Company’s asset retirement obligations during 2004 and 2003 (in thousands):


	2004			2003

Balance at beginning of year	$	1,163		$	1,056
Liabilities incurred*		1,277			173
Liabilities settled		(153	)		(100	)
Accretion expense		71			34

Asset retirement obligation at end of year	$	2,358		$	1,163


*	The 2004 amount includes $1,091 of liabilities assumed in the acquisition of TMBR.

Had SFAS 143 been in effect as of January 1, 2001, the impact on the Company’s results of operations would have been immaterial for the year ended December 31, 2002, and the asset retirement obligation would have been $1.1 million and $1.0 million as of December 31, 2002 and 2001, respectively. In addition, the cumulative effect of this change in accounting principle of approximately $469,000, net of tax, was recorded in the first quarter of 2003.


9.	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, 2004). 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 $49 million at December 31, 2004. There were no outstanding borrowings under the LOC at December 31, 2004. Costs of approximately $445,000 were expensed in 2004 to terminate the previous $100 million credit facility.


10.	Commitments, Contingencies and Other Matters

The Company maintains letters of credit in the aggregate amount of $49.0 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

F-18

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

coverages up to $50.0 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.

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 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.

The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition.

Other Matters — Effective January 29, 2004, the Company entered into Change in Control Agreements with its Chairman of the Board, Chief Executive Officer, President and Chief Operating Officer, two Senior Vice Presidents and Chief Financial Officer (the “Key Employees”). 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 and the Chief Financial Officer) 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 and the Chief Financial Officer).

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.


11.	Stockholders’ Equity

On June 7, 2004, the Company’s Board of Directors authorized a stock buyback program for the purchase of up to $30 million of outstanding shares of the Company’s 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). These shares are included in treasury stock at December 31, 2004.

F-19

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During the second quarter of 2004, the Company granted Restricted Shares to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended. 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. Compensation expense of approximately $773,000, net of tax, was included in net income for the year ended December 31, 2004.

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, 2002.

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. The next quarterly cash dividend is to be paid to holders of record on February 28, 2005 and paid on March 4, 2005. 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 2).

During March 2002, the Company issued 1.3 million shares (adjusted to reflect the two-for-one stock split on June 30, 2004) of its common stock as consideration for the acquisition of Odin Drilling, Inc. (see Note 2). The common stock was valued at $13.03 per share, its fair market value on the date the terms of the transaction were agreed upon.

F-20

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


12.	Stock Options and Warrants

Employee and Non-Employee Director Stock Option Plans — The Company has seven stock option plans of which three have shares available for grant. The remaining four plans are dormant and the Company does not intend to grant any further options under such plans. At December 31, 2004, 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. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”)(1)		16,500,000		7,711,776		2,997,992
Amended and Restated Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan (“2001 Plan”)(2)		2,000,000		1,346,322		78,161
Amended and Restated Non-Employee Director Stock Option Plan of Patterson-UTI Energy, Inc. (“Non-Employee Director Plan”)		1,200,000		370,000		485,000
Patterson-UTI Energy, Inc. Non-Employee Directors’ Stock Option Plan, as amended (“1995 Non-Employee Director Plan”)		240,000		24,000		—
1997 Stock Option Plan of DSI Industries, Inc. (“DSI Plan”)		—		2,144		—
Amended and Restated Patterson-UTI Energy, Inc. 1996 Employee Stock Option Plan (“1996 Plan”)		—		176,600		—
Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as amended (“1993 Plan”)		5,600,000		351,200		—


(1)	Plan is for the benefit of employees of the Company, including officers and directors of the Company.

(2)	Plan is for the benefit of employees of the Company, other than officers and directors of the Company.

The Company’s active plans are the 1997 Plan, the 2001 Plan and the Non-Employee Director Plan. A summary of each of these plans is set forth below.


	*1997 Plan*


	•	Administered by the Compensation Committee of the Board of Directors.

	•	All employees including officers and employee directors are eligible for awards.

	•	Vesting schedule is set by the Compensation Committee, however, typically options vest over 3 or 5 years.

	•	The Compensation Committee sets the term of the option except that no Incentive Stock Option (“ISO”) can have a term of longer than 10 years. Typically options granted under the plan have a term of 10 years.

	•	The options granted under the plan, unless otherwise stated in the grant thereof, vest upon a change of control as defined in the plan. Options granted to non-executive employees typically do not vest upon a change of control.

	•	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.

F-21

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	The plan allows for awards of tandem and independent stock appreciation rights, restricted stock and performance awards.


	*2001 Plan*

The terms and conditions of the 2001 Plan are identical to the 1997 Plan except as follows:


	•	Officers and directors of the Company are not eligible for grants of options under the 2001 Plan.

	•	No ISO’s may be awarded under the 2001 Plan.

	•	Unless the grant states otherwise, options granted under the 2001 Plan do not vest upon a change of control of the Company.


	*Non-Employee Director Plan*


	•	Administered by the Compensation Committee of the Board of Directors.

	•	All options vest upon the first anniversary of the option grant.

	•	Each director receives options to purchase 40,000 shares upon becoming a director of the Company and options to purchase 20,000 shares on December 31st of each subsequent year in which the director serves as a director of the Company.

	•	The exercise price of the options is the fair market value of the Company’s common stock on the date of grant.

1995 Non-Employee Director Plan — Options granted under the 1995 Non-Employee Director Plan vest on the first anniversary of the option grant. 1995 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 — The 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 — The 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.

Additional Options — In July 2001, the Compensation Committee granted to each of two non-employee directors of the Company an option to purchase 24,000 shares of the Company’s common stock. These options vested on November 6, 2001 and terminate on November 5, 2005. The exercise price of each of the options was $14.3125, which was in excess of the fair market value of the Company’s common stock on the date of grant.

F-22

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of the status of the Company’s stock options issued as of December 31, 2004, 2003 and 2002 and the changes during each of the years then ended are presented below (in thousands, except weighted average exercise price):


		2004					2003					2002

		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			12,276		$	10.31		12,277		$	8.81		13,192		$	5.20
	Granted		640			19.19		1,830			16.24		4,297			13.39
	Exercised		(2,852	)		5.55		(1,736	)		5.92		(4,914	)		3.21
	Surrendered/ Expired		(58	)		8.76		(95	)		9.99		(298	)		7.66

Outstanding at end of year			10,006		$	12.24		12,276		$	10.31		12,277		$	8.81

Exercisable at end of year			6,377		$	11.68		5,972		$	8.15		4,790		$	5.44

The following table summarizes information about stock options outstanding at December 31, 2004:


	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		416,668		4.23	$	2.31		416,668	$	2.31
$ 2.51 to $ 5.00		98,000		3.16	$	4.94		98,000	$	4.94
$ 5.01 to $ 7.50		156,344		2.70	$	7.32		156,344	$	7.32
$ 7.51 to $10.00		2,576,227		6.45	$	8.02		1,365,617	$	8.08
$ 10.01 to $12.50		95,000		2.88	$	11.44		95,000	$	11.44
$ 12.51 to $15.00		4,103,803		7.50	$	13.35		3,085,833	$	13.28
$ 15.01 to $19.45		2,560,000		7.98	$	16.95		1,159,998	$	16.19

		10,006,042		7.06	$	12.24		6,377,460	$	11.68

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 2004 respectively; dividend yield of 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 and 36.84% for all 2004 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-23

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In June 2000, the Company issued 254,000 warrants exercisable at $11 per share as partial consideration for the purchase of eight drilling rigs and related equipment from High Valley Drilling, Inc. The warrants were fully exercisable at the date of issuance. All of the warrants were exercised in 2003 and 2002.

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
	2004		640	$	19.19
	2003		1,830		16.24
	2002		4,297		13.39
Exercised
	2004		3,502	$	7.00
	2003		1,941		6.46
	2002		4,963		3.28
Surrendered
	2004		58	$	8.76
	2003		95		9.99
	2002		298		7.66
Outstanding at Year End
	2004		10,006	$	12.24
	2003		12,926		10.47
	2002		13,132		9.07
Exercisable at Year End
	2004		6,377	$	11.68
	2003		6,622		8.66
	2002		5,645		6.56


13.	Leases

The Company incurred rent expense, consisting primarily of daily rental charges for the use of drilling equipment, of $9.1 million, $8.6 million and $5.7 million, for the years 2004, 2003 and 2002, respectively. The Company’s obligations under non-cancelable operating lease agreements are not material to the Company’s operations.

F-24

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


14.	Income Taxes

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


		2004		2003		2002

Federal income tax expense (benefit):
	Current	$	32,438	$	13,856	$	(18,064	)
	Deferred		20,375		15,143		21,844

			52,813		28,999		3,780
State income tax expense (benefit):
	Current		2,015		1,214		(1,811	)
	Deferred		2,170		76		1,117

			4,185		1,290		(694	)
Foreign income tax expense (benefit):
	Current		5,235		18		(2,003	)
	Deferred		928		2,689		744

			6,163		2,707		(1,259	)
Total:
	Current		39,688		15,088		(21,878	)
	Deferred		23,473		17,908		23,705

Total income tax expense		$	63,161	$	32,996	$	1,827

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


	2004			2003			2002

Statutory tax rate		35.0	%		35.0	%		35.0	%
State income taxes		1.6			1.5			2.8
Permanent differences		0.4			0.8			5.7
Other, net		(0.3	)		(0.6	)		—

Effective tax rate		36.7	%		36.7	%		43.5	%

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, 2004 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-25

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):


			December 31,			Net			December 31,			Net			December 31,			Net			January 1,
			2004			Change			2003			Change			2002			Change			2002

Deferred tax assets:
	Current:
		Federal net operating loss carryforwards	$	1,870		$	1,870		$	—		$	—		$	—		$	—		$	—
		Workers’ compensation allowance		14,877			1,545			13,332			6,159			7,173			2,663			4,510
		AMT credit		—			(602	)		602			—			602			—			602
		Other		6,978			1,238			5,740			(1,775	)		7,515			3,880			3,635

				23,725			4,051			19,674			4,384			15,290			6,543			8,747

	Non-current:
		Federal net operating loss carryforwards		4,115			4,115			—			—			—			—			—
		AMT credit		118			118			—			—			—			—			—
		Federal benefit of foreign deferred tax liabilities		6,708			933			5,775			2,019			3,756			744			3,012
		Federal benefit of state deferred tax liabilities		4,160			639			3,521			1,470			2,051			556			1,495
		Other		763			763			—			—			—			—			—

				15,864			6,568			9,296			3,489			5,807			1,300			4,507

Total deferred tax assets				39,589			10,619			28,970			7,873			21,097			7,843			13,254

Deferred tax liabilities:
	Current:
		Other		(7,734	)		(4,509	)		(3,225	)		(3,225	)		—			—			—
	Non-current:
		Property and equipment basis difference		(177,637	)		(27,182	)		(150,455	)		(18,077	)		(132,378	)		(35,607	)		(96,771	)
		Other		(267	)		1,883			(2,150	)		(1,575	)		(575	)		20			(595	)

				(177,904	)		(25,299	)		(152,605	)		(19,652	)		(132,953	)		(35,587	)		(97,366	)

Total deferred tax liabilities				(185,638	)		(29,808	)		(155,830	)		(22,877	)		(132,953	)		(35,587	)		(97,366	)

Net deferred tax liability			$	(146,049	)	$	(19,189	)	$	(126,860	)	$	(15,004	)	$	(111,856	)	$	(27,744	)	$	(84,112	)

Other deferred tax assets consist primarily of various allowance accounts and tax deferred expenses expected to generate future tax benefit of approximately $7 million. Other deferred tax liabilities consist primarily of receivables from insurance companies not yet recognized for tax purposes.

For tax purposes, the Company has available at December 31, 2004, Federal net operating loss carryforwards of approximately $16 million and $118,000 of alternative minimum tax credit carryforwards. These carryforwards are attributable to the acquisition of TMBR in February 2004.

F-26

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


15.	Employee Benefits

The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses of approximately $2.2 million in 2004, $1.5 million in 2003 and $2.1 million in 2002 for the Company’s discretionary contributions to the plan.


16.	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, 2004, the Company owned 361 drilling rigs, of which 149 of the drilling rigs were based in the Permian Basin region, 55 in South Texas, 42 in the Ark-La-Tex region and Mississippi, 77 in the Mid-Continent region, 21 in the Rocky Mountain region and 17 in Western Canada. The Company operated 259 of its drilling rigs in 2004.

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 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. 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-27

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,

		2004			2003			2002

Revenues:
	Contract drilling(a)	$	815,683		$	640,788		$	410,752
	Pressure pumping		66,654			46,083			32,996
	Drilling and completion fluids(b)		90,858			69,286			69,966
	Oil and natural gas		33,867			21,163			14,723

Total segment revenues			1,007,062			777,320			528,437
	Elimination of intercompany revenues(a)(b)		(6,293	)		(1,150	)		(480	)

Total revenues		$	1,000,769		$	776,170		$	527,957

Income before income taxes:
	Contract drilling	$	150,047		$	75,666		$	7,607
	Pressure pumping		16,747			10,442			6,090
	Drilling and completion fluids		4,162			(1,960	)		(278	)
	Oil and natural gas		10,764			7,784			3,945

			181,720			91,932			17,364
	Corporate and other		(10,506	)		(7,194	)		(9,266	)
	Restructuring and other charges(c)		—			2,452			(4,700	)
	Interest income		1,140			1,116			1,110
	Interest expense		(695	)		(292	)		(532	)
	Other		235			1,870			225

Income before income taxes		$	171,894		$	89,884		$	4,201


(a)	Includes contract drilling intercompany revenues of approximately $6.0 million, $1.1 million and $457,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

(b)	Includes drilling and completion fluids intercompany revenues of approximately $301,000, $56,000 and $23,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

(c)	Restructuring and 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.

F-28

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Years Ended December 31,

		2004		2003		2002

Identifiable assets:
	Contract drilling	$	1,044,147	$	809,896	$	694,020
	Pressure pumping		62,866		46,763		35,084
	Drilling and completion fluids		38,196		30,860		34,687
	Oil and natural gas		66,734		33,494		20,854

			1,211,943		921,013		784,645
	Corporate and other(a)		110,968		163,101		158,178

Total assets		$	1,322,911	$	1,084,114	$	942,823

Depreciation, depletion, amortization and impairment:
	Contract drilling	$	98,334	$	84,379	$	80,500
	Pressure pumping		5,112		3,774		2,803
	Drilling and completion fluids		2,196		2,319		2,216
	Oil and natural gas		13,309		7,082		5,251

			118,951		97,554		90,770
	Corporate and other		444		444		446

Total depreciation, depletion and amortization		$	119,395	$	97,998	$	91,216

Capital expenditures:
	Contract drilling	$	157,916	$	95,175	$	68,516
	Pressure pumping		17,705		10,524		7,399
	Drilling and completion fluids		1,488		912		1,571
	Oil and natural gas		14,451		10,015		6,357

Total capital expenditures		$	191,560	$	116,626	$	83,843


(a)	Corporate assets primarily include cash on hand managed by the parent corporation and certain deferred Federal income tax assets.

F-29

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


17.	Quarterly Financial Information (unaudited)

Quarterly financial information for the years ended December 31, 2004 and 2003 is as follows (in thousands, except per share amounts):


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

2004
Operating revenues			$	218,779		$	234,510	$	259,174	$	288,306
Operating income				32,510			30,799		47,408		60,497
Net income				20,682			19,607		29,964		38,480
Earnings per share:
	Basic		$	0.12		$	0.12	$	0.18	$	0.23
	Diluted		$	0.12		$	0.12	$	0.18	$	0.23
2003
Operating revenues			$	165,239		$	195,624	$	207,015	$	208,292
Operating income				9,844			19,153		27,354		30,839
Income before cumulative effect of change in accounting principle				7,051			12,202		17,186		20,449
Cumulative effect of change in accounting principle, net of related income tax benefit of approximately $287				(469	)		—		—		—
Net income				6,582			12,202		17,186		20,449
Earnings per share:
	Basic:
		Income before cumulative effect of change in accounting principle	$	0.04		$	0.08	$	0.11	$	0.13
		Net income	$	0.04		$	0.08	$	0.11	$	0.13
	Diluted:
		Income before cumulative effect of change in accounting principle	$	0.04		$	0.07	$	0.10	$	0.12
		Net income	$	0.04		$	0.07	$	0.10	$	0.12


18.	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.

F-30

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company believes that it places its demand deposits and temporary cash investments with high credit quality financial institutions. At December 31, 2004 and 2003, the Company’s demand deposits and temporary cash investments consisted of the following (in thousands):


	2004			2003

Deposits in FDIC and SIPC-insured institutions under $100,000	$	2,023		$	(3,326	)
Deposits in FDIC and SIPC-insured institutions over $100,000		131,427			112,226

		133,450			108,900
Less outstanding checks and other reconciling items		(21,079	)		(8,417	)

Cash and cash equivalents	$	112,371		$	100,483

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, 2004, 2003, or 2002. The Company recognized bad debt expense for 2004, 2003 and 2002 of $897,000, $259,000 and $320,000, 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.


19.	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, 2004, affiliated persons were working interest owners in 237 of 300 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 $13.8 million, $11.1 million and $6.9 million from these properties in 2004, 2003 and 2002, respectively. These persons or entities in turn paid for joint operating costs (including drilling and other development expenses) of $7.5 million, $7.9 million and $5.5 million incurred in 2004, 2003 and 2002, respectively. These activities resulted in a payable to the affiliated persons of approximately $1.2 million and $871,000 and a receivable from the affiliated persons of approximately $856,000 and $888,000 at December 31, 2004 and 2003, respectively.

Other — In 2004, 2003 and 2002, the Company paid approximately $914,000, $740,000 and $279,000, respectively, to TMP Truck and Trailer LP (“TMP”), an entity 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 2004 and 2003, the Company paid approximately $39,000 and $209,000, respectively, to Melco Services (“Melco”) for dirt contracting services and $44,000 and $59,000, 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 Chief Financial Officer. Purchases from Melco and L&N were at current market prices.

F-31

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


20.	Supplementary Oil and Natural Gas Reserve Information and Related Data (Unaudited)


	*Oil and Natural Gas Expenditures and Capitalized Costs:*

Gross oil and natural gas expenditures for the years ended December 31, 2004, 2003 and 2002 are summarized below (in thousands):


	2004		2003		2002

Property acquisition costs	$	2,491	$	1,120	$	905
Exploration costs		10,242		7,572		6,267
Development costs		1,855		1,531		845

	$	14,588	$	10,223	$	8,017

The aggregate amount of capitalized costs of oil and natural gas properties as of December 31, 2004, 2003 and 2002 is comprised of the following (in thousands):


	2004			2003			2002

Proved properties	$	71,731		$	50,481		$	44,849
Unproved properties		10,980			7,144			7,162
Accumulated depreciation and depletion		(45,506	)		(38,947	)		(35,684	)

	$	37,205		$	18,678		$	16,327


	*Results of operations for oil and natural gas producing activities:*

Results of operations for oil and natural gas producing activities as of December 31, 2004, 2003 and 2002 are summarized below (in thousands):


	2004		2003		2002

Oil and natural gas sales	$	31,142	$	19,058	$	12,738
Gain on sale of oil and natural gas properties		123		571		303

		31,265		19,629		13,041

Costs and expenses:
Lease operating and production costs		6,076		3,735		3,171
Exploration costs including dry holes and abandonments		1,902		1,073		785
Depreciation and depletion		10,112		5,638		4,524
Impairment of oil and natural gas properties		3,197		1,444		727
Income tax expense		3,662		2,840		1,687

		24,949		14,730		10,894

Results of operations for oil and natural gas producing activities	$	6,316	$	4,899	$	2,147

F-32

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Oil and natural gas reserve quantities:*

The following table sets forth information (in thousands) with respect to quantities of net proved oil and natural gas reserves and changes in those reserves for the years ended December 31, 2004, 2003 and 2002. The quantities were estimated by an independent petroleum engineer. The Company’s proved oil and natural gas reserves are located entirely within the United States.


	Oil (Bbls)			Gas (Mcf)

Estimated quantity, January 1, 2002		1,047			4,634
Revision in previous estimates		145			2,103
Extensions, discoveries and other additions		331			1,420
Sales of reserves		(12	)		(110	)
Production		(284	)		(1,807	)

Estimated quantity, January 1, 2003		1,227			6,240
Revision in previous estimates		87			(1,123	)
Extensions, discoveries and other additions		149			2,446
Sales of reserves		(27	)		(244	)
Production		(289	)		(2,052	)

Estimated quantity, January 1, 2004		1,147			5,267
Revision in previous estimates		(122	)		(1,807	)
Extensions, discoveries and other additions		392			2,675
Purchases		695			4,920
Sales of reserves		(6	)		(90	)
Production		(392	)		(2,719	)

Estimated quantity, January 1, 2005		1,714			8,246

Estimates of the Company’s proved reserves and future net revenues are determined based on various assumptions such as oil and natural gas prices, operating costs, reservoir performance and economic conditions. The oil and natural gas prices and operating cost assumptions were based on the actual prices and costs in effect as of the date of such estimates. These assumptions are held constant throughout the life of the properties, except operating costs are adjusted for contractual escalations. The Company’s independent petroleum engineer estimates the assumptions relating to reservoir performance and economic conditions using information available and industry experience. The oil and natural gas prices used to value the Company’s reserves as of December 31, 2004 were $43.45 per Bbl of oil and $6.15 per Mcf of natural gas. Estimates of reserves and production performance are subjective and may change materially as actual production information becomes available.

F-33

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Standardized measure of future net cash flows of proved developed oil and natural gas reserves, discounted at 10% per annum (in thousands):*


	Years Ended December 31,

	2004			2003			2002

Future gross revenues	$	123,201		$	70,894		$	68,165
Future development and production costs		(37,820	)		(23,021	)		(22,149	)
Future income tax expense		(30,995	)		(15,155	)		(15,964	)

Future net cash flows		54,386			32,718			30,052
Discount at 10% per annum		(16,844	)		(8,768	)		(8,952	)

Standardized measure of discounted future net cash flows	$	37,542		$	23,950		$	21,100


	*Changes in the standardized measure of net cash flows of proved developed oil and natural gas reserves discounted at 10% per annum (in thousands):*


	Years Ended December 31,

	2004			2003			2002

Standardized measure at beginning of year	$	23,950		$	21,100		$	10,714
Sales and transfers of oil and natural gas produced, net of production costs		(15,257	)		(11,362	)		(8,342	)
Net changes in sales price and future production and development costs		6,619			4,718			4,888
Extensions, discoveries and improved recovery, less related costs		8,259			10,052			6,017
Sales of minerals-in-place		(676	)		(2,017	)		(30	)
Purchase of reserves		19,561			—			—
Revision of previous quantity estimates		4,288			(2,976	)		4,315
Accretion of discount		3,759			3,547			1,531
Other		(3,953	)		101			(9,358	)
Net change in income taxes		(9,008	)		787			11,365

Standardized measure at end of year	$	37,542		$	23,950		$	21,100

F-34

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, 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
Year Ended December 31, 2002
Deducted from asset accounts:
	Allowance for doubtful accounts	$	4,021	$	320	$	1,197	$	3,144


(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 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: February 25, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on behalf of Patterson-UTI Energy, Inc. and in the capacities indicated as of February 25, 2005.


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/ JONATHAN D. NELSON Jonathan D. Nelson (Principal Financial and Accounting Officer)				Vice President, 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


2	.1	Asset Purchase Agreement among Key Energy Drilling, Inc., Key Energy Drilling Beneficial, L.P., Key Rocky Mountain, Inc., Key Four Corners, Inc. and Key Energy Services, Inc. and Patterson-UTI Drilling Company LP, LLLP and Patterson-UTI Energy, Inc., dated as of December 7, 2004.
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 2.1, 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	Stock Option Agreement dated July 20, 2001 between Patterson-UTI Energy, Inc. and Kenneth R. Peak (filed March 19, 2002 as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 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 Jonathan D. Nelson (filed August 9, 2004 as Exhibit 10.5 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	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	.17	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	.18	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	.19	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	.20	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	.21	Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Jonathan D. Nelson (filed on February 4, 2004 as Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).*
10	.22	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	.23	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.*
10	.24	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, Jonathan D. Nelson 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	.25	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	.26	Summary Description of 2003 Cash Bonus Plan.*


10	.27	Summary Description of Director Compensation.*
14	.1	Patterson-UTI Energy, Inc. Code of Business Conduct and Ethics for Senior Financial Executives (filed 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.
23	.2	Consent of Independent Petroleum Engineer — M. Brian Wallace, P.E.
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.

Exhibit 2.1



ASSET PURCHASE AGREEMENT

among

Key Energy Drilling, Inc.

Key Energy Drilling beneficial, L.P.

Key rocky mountain, inc.

Key four corners, inc.

and

Key Energy Services, Inc.

and

Patterson-UTI Drilling Company LP, LLLP

and

Patterson-UTI Energy, Inc.

Dated as of December 7, 2004

TABLE OF CONTENTS


		Page

ARTICLE 1 PURCHASE AND SALE OF ASSETS			1

	1.1 Purchase and Sale of the Assets		1
	1.2 Purchase Price		2
	1.3 Liabilities		2
	1.4 Assumption of Risk by Buyer/Dayrates		2
	1.5 Closing		2
	1.6 Closing Deliveries		3
	1.7 Undelivered Certificates of Title		3
	1.8 Purchase Price Adjustment		4

ARTICLE 2 REPRESENTATIONS AND WARRANTIES			4

	2.1 Representations and Warranties of Parent and the Sellers		4
	2.2 Representations and Warranties of Buyer and Patterson		8

ARTICLE 3 OBLIGATIONS PENDING CLOSING DATE			9

	3.1 Agreements of Parent and Sellers		9
	3.2 Supplemental Information		10
	3.3 Regulatory and Other Authorizations		10

ARTICLE 4 CONDITIONS PRECEDENT TO OBLIGATIONS			11

	4.1 Conditions Precedent to Obligations of Buyer		11
	4.2 Conditions Precedent to Obligations of Sellers		12

ARTICLE 5 TERMINATION AND ABANDONMENT			13

	5.1 Termination		13
	5.2 Termination by Board of Directors		13
	5.3 Effect of Termination		13
	5.4 Waiver of Conditions		13

ARTICLE 6 ADDITIONAL AGREEMENTS			14

	6.1 Employees		14
	6.2 Trademarks		14
	6.3 Further Assurances		14
	6.4 Public Announcements		14
	6.5 No Solicitation		14
	6.6 Taking Possession of Certain Assets		14
	6.7 Payment of Sales Taxes		15
	6.8 Termination of Leases		15
	6.9 Environmental Inspection		15
	6.10 WARN Act		15
	6.11 Closing in the Event of HSR Early Termination		15


		Page

ARTICLE 7 INDEMNIFICATION			15

	7.1 Indemnification by each of the Parent and Sellers		15
	7.2 Indemnification by Patterson and Buyer		16
	7.3 Indemnification Procedure		16
	7.4 Limitation on Damages		17
	7.5 Liability Exception		17
	7.6 Exclusive Remedy		17

ARTICLE 8 MISCELLANEOUS			17

	8.1 Materiality		17
	8.2 Survival of Representations, Warranties and Covenants		18
	8.3 Entirety		18
	8.4 Counterparts		18
	8.5 Notices and Waivers		18
	8.6 Limitations on Assignment		19
	8.7 No Negotiation		19
	8.8 Convenience of Forum; Consent to Jurisdiction		20
	8.9 Enforcement of the Agreement		20
	8.10 Table of Contents and Captions		20
	8.11 Successors and Assigns		20
	8.12 Severability		20
	8.13 Applicable Law		20

ASSET PURCHASE AGREEMENT

THIS ASSET PURCHASE AGREEMENT (this “Agreement”) is entered into as of December 7, 2004, among Key Energy Drilling, Inc., a Delaware corporation (“Key Drilling”), Key Energy Drilling Beneficial, L.P., a Texas limited partnership (“Key Drilling L.P.”), Key Four Corners, Inc., a Delaware corporation (“Key Four Corners”) and Key Rocky Mountain, Inc., a Delaware corporation (“Key Rocky Mountain”, and together with Key Drilling, Key Four Corners and Key Rocky Mountain, the “Sellers”), Key Energy Services, Inc., a Maryland corporation (“Parent”) and Patterson-UTI Drilling Company LP, LLLP, a Delaware limited liability limited partnership (“Buyer”) and Patterson-UTI Energy, Inc., a Delaware corporation (“Patterson”).

WHEREAS, Key Drilling, Key Four Corners and Key Rocky Mountain are the record owners of the Assets (defined below) being sold to the Buyer pursuant to this Agreement; and

WHEREAS, Key Drilling L.P. is the beneficial owner of the Assets owned by Key Drilling being sold to the Buyer pursuant to this Agreement; and

WHEREAS, Parent directly or indirectly owns all of the equity of the Sellers; and

WHEREAS, Patterson directly or indirectly owns all of the equity of Buyer; and

WHEREAS, the Sellers desire to sell to Buyer, and Buyer desires to purchase from the Sellers, the Assets.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein contained, the parties hereto hereby agree as follows:

ARTICLE 1

PURCHASE AND SALE OF ASSETS

1.1 Purchase and Sale of the Assets . Subject to the terms and conditions set forth in this Agreement, the Sellers agree to sell, convey, transfer, assign and deliver to the Buyer the following assets of the Sellers (all of such assets being sold hereunder are referred to collectively herein as the “Assets”):

(a)   the real property and real property leases described on Schedule 1.1(a) hereto (the “Real Property”);

(b)   the tangible personal property of the Sellers (such as land drilling rigs, drilling components, engines, machinery, spare parts, trucks, transport trailers and equipment associated with any of the foregoing) described on Schedule 1.1(b) hereto;

(c)   all supplies and other inventory of the Sellers used or held for use in connection with the operation of the property described in Section 1.1(b) ;

(d) those contracts, contract rights, obligations and agreements of the Sellers relating to the Assets listed on Schedule 1.1(d) hereto (collectively, the “Purchased Contracts”);

1.2 Purchase Price. As consideration for the sale of the Assets and for the other covenants and agreements of the Sellers contained herein, the Buyer agrees to pay to the Sellers, on the Closing Date (defined below), an aggregate purchase price of $62,000,000, subject to adjustment as provided in Section 1.8 (the “Purchase Price”), in immediately available funds to accounts designated by the Sellers.

1.3 Liabilities . Effective on the Closing Date, the Buyer shall assume (i) those, and only those, liabilities and obligations of the Sellers to be performed by Sellers under the Purchased Contracts after the Closing Date; (ii) any liabilities or obligations asserted by any person relating to the condition or the operation of the Assets after the Closing Date; (iii) any liabilities or obligations asserted by any person after the Closing Date relating to the condition of the Real Property (the “Assumed Liabilities”); provided, however , that the Assumed Liabilities shall not include any liability or obligations of Sellers required to be performed after the Closing date arising out of any breach by Sellers of the terms of the Purchased Contracts or any defect, breach of warranty, negligence or other deficiency with respect to matters performed or required to be performed under the Purchased Contracts on or prior to the Closing Date. The Sellers shall be responsible for any and all liabilities and obligations of the Sellers other than the Assumed Liabilities. All of the Sellers’ liabilities other than the Assumed Liabilities are referred to herein as the “Retained Liabilities” and include, without limitation, (i) any obligations arising on or before Closing Date from the Sellers’ employment of any employee, independent contractor, consultant, agent or advisor, and any bonus (other than the Retention Bonuses referred to below), retirement, severance, job security or similar benefit related thereto; (ii) any failure to pay any Taxes (as defined in Section 2.1.3 ) owed by the Sellers that are applicable to the period ending with the Closing Date; and (iii) any liabilities or obligations relating to the condition or the operation of the Assets on or before the Closing Date (other than liabilities or obligations included in Assumed Liabilities pursuant to clause (iii) above). Notwithstanding clause (i) of the preceding sentence, the Buyer shall pay the retention bonuses (the “Retention Bonuses”) to those persons named on Schedule 1.3 who are hired by the Buyer in the amount set forth opposite such individual’s name.

1.4 Assumption of Risk by Buyer/Dayrates . Buyer specifically assumes all risk of death, injury, loss or damage to Buyer or any other party arising from or relating to the use, condition or operation of the Assets after the Closing Date. Dayrates and other benefits earned as well as costs incurred on the Purchased Contracts on or before the Closing Date (whether or not invoiced or billed as of the Closing Date) shall be for the benefit and account of Sellers and dayrates and other benefits earned as well as costs incurred on the Purchased Contracts after the Closing Date shall be for the benefit and account of the Buyer; any payments or other consideration received on the Purchased Contracts by Sellers or Buyer shall be divided between Seller and Buyer according to these principles.

1.5 Closing . Consummation of the transactions contemplated by this Agreement (the “Closing”) shall take place at the offices of Porter & Hedges, L.L.P., 700 Louisiana Street,

Houston, Texas 77002, within three business days after all of the conditions at closing set forth in Article 4 have been satisfied or waived in accordance with Section 5.4 (the “Closing Date”).

1.6 Closing Deliveries .

1.6.1 Deliveries of the Seller. At the Closing, in addition to the conveyance of the Assets from the Sellers to the Buyer in exchange for the Purchase Price, the Sellers will deliver or cause to be delivered to the Buyer:

1.6.1.1 Any assignment and bill of sale or deed necessary to effectively transfer record and beneficial ownership of the Assets to the Buyer;

1.6.1.2 All required certificates and documents of title (other than the Undelivered Certificates of Title (defined below)) relating to the Assets being purchased by the Buyer duly executed and endorsed for transfer to the Buyer;

1.6.1.3 Releases of all liens to which any of the Assets were subject before the Closing;

1.6.1.4 All written consents required to be delivered pursuant to Section 2.1.9 or otherwise;

1.6.1.5 All other deliveries required to be delivered by the Sellers to the Buyer pursuant to Article 4 here;

1.6.1.6 Evidence reasonably satisfactory to Buyer as to the termination of the leases as required by Section 6.8 ; and

1.6.1.7 All other deliveries reasonably requested by the Buyer to be delivered by the Sellers.

1.6.2 Deliveries of the Buyer. At the Closing the Buyer will deliver or cause to be delivered to the Seller:

1.6.2.1 The Purchase Price;

1.6.2.2 All deliveries required to be delivered by the Buyer to the Sellers pursuant to Article 4 of this Agreement; and

1.6.2.3 All other deliveries reasonably requested by the Sellers to be delivered by the Buyer.

1.7 Undelivered Certificates of Title . The Buyer and the Sellers acknowledge that the Sellers may be unable to deliver to the Buyer those certificates of title (the “Undelivered Certificates of Title”) identified on Schedule 1.7 hereto. The Sellers hereby agree to deliver, or cause to be delivered, to the Buyer, within 120 days from the Closing Date, the Undelivered Certificates of Title, and all lien releases, if any, in connection therewith.

1.8 Purchase Price Adjustment . All amounts paid or payable for real estate and ad valorem taxes shall be prorated as of the Closing Date, Sellers being charged and credited for all of same up to and including the Closing Date and Buyer being charged and credited for all of same after such date. If the actual amounts to be prorated are not known as of the Closing Date, the prorations shall be made on the basis of the best evidence then available, and thereafter, when actual figures are received.

ARTICLE 2

REPRESENTATIONS AND WARRANTIES

2.1 Representations and Warranties of Parent and the Sellers . Each of the Parent and the Sellers, jointly and severally, as of the date hereof and as of the Closing Date, represents and warrants to Buyer and Patterson as follows:

2.1.1 Organization and Standing

2.1.1.1 Key Drilling . Key Drilling is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, has full requisite corporate power and authority to carry on its business as it is currently conducted, and to own and operate the properties currently owned and operated by it, and is duly qualified or licensed to do business and is in good standing as a foreign corporation authorized to do business in all jurisdictions in which the character of the properties owned or the nature of the business conducted by it would make such qualification or licensing necessary, except where the failure to be so qualified or licensed would not have a Material Adverse Effect (as defined in Section 8.1 ) on the Assets.

2.1.1.2 Key Drilling L.P. Key Drilling L.P. is a limited partnership duly organized, validly existing and in good standing under the laws of the State of Texas, has full requisite limited partnership power and authority to carry on its business as it is currently conducted, and to own and operate the properties currently owned and operated by it, and is dully qualified or licensed to do business and is in good standing as a foreign limited partnership authorized to do business in all jurisdictions in which the character of the properties owned or the nature of the business conducted by it would make such qualification or licensing necessary, except where the failure to be so qualified or licensed would not have a Material Adverse Effect on the Assets.

2.1.1.3 Key Four Corners . Key Four Corners is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, has full requisite corporate power and authority to carry on its business as it is currently conducted, and to own and operate the properties currently owned and operated by it, and is duly qualified or licensed to do business and is in good standing as a foreign corporation authorized to do business in all jurisdictions in which the character of the properties owned or the nature of the business conducted by it would make such qualification or licensing necessary,

except where the failure to be so qualified or licensed would not have a Material Adverse Effect on the Assets.

2.1.1.4 Key Rocky Mountain . Key Rocky Mountain is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, has full requisite corporate power and authority to carry on its business as it is currently conducted, and to own and operate the properties currently owned and operated by it, and is duly qualified or licensed to do business and is in good standing as a foreign corporation authorized to do business in all jurisdictions in which the character of the properties owned or the nature of the business conducted by it would make such qualification or licensing necessary, except where the failure to be so qualified or licensed would not have a Material Adverse Effect on the Assets.

2.1.2 Agreement Authorized and its Effect on Other Obligations . Each of the Parent and the Sellers has the legal capacity and requisite power and authority to enter into, and perform its obligations under this Agreement. The consummation of the transactions, contemplated by this Agreement have been duly and validly authorized by all necessary corporate action on the part of each of the Parent and the Sellers, and this Agreement is the valid and binding obligation of each of the Parent and the Sellers, enforceable against each of the Parent and the Sellers in accordance with its terms, except as enforceability may be limited by (a) equitable principles of general applicability, or (b) bankruptcy, insolvency, reorganization, fraudulent conveyance or similar laws affecting the rights of creditors generally. The execution, delivery and performance of this Agreement by the Parent and the Sellers will not conflict with or result in a violation or breach of any term or provision of, nor constitute a default under (i) the organizational documents of any of the Parent and the Sellers; (ii) any obligation, indenture, mortgage, deed of trust, lease, contract or other agreement to which any of them is a party or by which any of them or their properties are bound or (iii) any requirement of statute, law, regulation, judgment, decree or order of any governmental authority or judicial body.

2.1.3 Taxes . All federal, state and local income, sales, use, franchise, gross, revenue, payroll, excise, property, customs, duties and all other taxes (collectively, the “Taxes”) that apply to the ownership, use and operation of the Assets or that could in any way create a lien, charge or encumbrance on the Assets have been paid in full (other than liens, charges or encumbrances on the Assets as set forth on Schedule 2.1.3 , which are being contested in good faith by Sellers) and all tax returns or reports related thereto have been filed with appropriate governmental agencies, domestic and foreign, by each of the Sellers for each period for which any such returns, reports, or estimates were due (taking into account any extensions of time to file before the date hereof). Except as disclosed on Schedule 2.1.3 , no waivers of any statute of limitations executed by any of the Sellers with respect to federal income or other Taxes are in effect. Except as disclosed on Schedule 2.1.3 , no income or franchise tax return of any of the Sellers have been examined by the IRS or the taxing authorities of any other jurisdiction. There are no Tax liens on any assets of any of the Sellers except for Taxes not yet currently due and at the time of Closing all Taxes shall have been paid in full except for Taxes being contested in good faith by Sellers or Taxes not yet due and payable.

2.1.4 Title to Assets . Schedule 2.1.4 sets forth all Encumbrances on the Assets. As of the Closing Date, Sellers, collectively, will have good, indefeasible and marketable title to the Assets, free and clear of any Encumbrance. The Sellers have the absolute right to sell the Assets to the Buyer and upon consummation of the transactions contemplated hereby the Buyer will have good and marketable title to the Assets free and clear of any Encumbrances. For purposes of this Agreement the term “Encumbrances” means all liens, including tax liens, security interests, pledges, mortgages, deeds of trust, claims, rights of first refusal, options, charges, restrictions or conditions to transfer or assignment, liabilities, obligations, privileges, equities, easements, rights of way, limitations, reservations, restrictions and other encumbrances of any kind or nature.

2.1.5 Inspection; Limitation on Warranty . Buyer has advised Sellers that Buyer inspected the Assets to Buyer’s satisfaction during November 2004. As of the date of this Agreement and as of the Closing Date, the Assets are, and will be, in the same locations as inspected (or within 50 miles thereof) and in substantially the same condition as when inspected by Buyer, subject only to reasonable wear and tear. As a material part of the consideration for this Agreement, Sellers and Buyer agree that Buyer is taking the Assets “AS IS” with any and all faults, latent and patent defects and that there is no warranty by Sellers that the Assets are fit for a particular purpose. Buyer acknowledges that it is not relying upon any representation, statement or other assertion with respect to the condition of the Assets, but is relying upon its examination of the Assets. Buyer takes the Assets under the express understanding there are no express warranties or implied warranties (except as provided in this Article 2 ). Except as provided in this Article 2 , neither Parent nor Sellers make any guaranty, warranty or representation, express or implied, by operation of law or otherwise, as to the quality, serviceability, merchantability or condition of the Assets, or their fitness for any use or purpose.

2.1.6 Contracts . Sellers have delivered to Buyer true, correct and complete copies of the Purchased Contracts. All of the Purchased Contracts are in full force and effect, and constitute valid and binding obligations of the Sellers. Sellers are not in default under any Purchased Contracts and to Sellers knowledge no other parties thereto are in default.

2.1.7 Litigation . There is no claim, suit, action, or legal, administrative, arbitration, or other proceeding or governmental investigation pending, or to the knowledge of either Seller threatened, to which either of the Sellers is a party or, to the knowledge of either of the Sellers, might become a party, which affects the Assets or the transactions contemplated by this Agreement.

2.1.8 Investigations; Litigation . Except as required pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1978 and the rules and regulations promulgated thereunder (“HSR”), no investigation or review by any governmental entity with respect to any of the Parent or Sellers or any of the transactions contemplated by this Agreement is pending or, to the knowledge of any of the Parent or Sellers, threatened, nor has any governmental entity indicated to any of the Parent or Sellers an intention to conduct the same.

2.1.9 Consents and Approvals . Except as required by HSR and set forth on Schedule 2.1.9 , and subject to Section 8.6 , no consent, approval or authorization of, or filing or registration with, any governmental or regulatory authority, or any other person or entity is required to be made or obtained by any of Parent or the Sellers in connection with the execution, delivery or performance of this Agreement or the consummation of the transactions contemplated hereby.

2.1.10 Finder’s Fee . Other than as set forth in Schedule 2.1.10 , all negotiations relative to this Agreement and the transactions contemplated hereby have been carried on by the Sellers and their counsel directly with Buyer and its counsel, without the intervention of any other person in such manner as to give rise to any valid claim against any of the parties hereto for a brokerage commission, finder’s fee or any similar payments.

2.1.11 Compliance With Laws . Sellers are in compliance in all material respects with all applicable laws and regulations relating to its ownership or operation of the Assets, and have not received notice of any violation (that is uncured or outstanding) of any law or regulation relating to its operation of the Assets.

2.1.12 Solvency . Each of Parent and the Sellers are now solvent, and neither the Parent nor Sellers will be rendered insolvent by the occurrence of the transactions contemplated by this Agreement. In addition, immediately after giving effect to the consummation of the transactions contemplated by this Agreement, (i) each of the Parent and Sellers will be able to pay its debts as they become due, (ii) the property of the Parent and Sellers does not and will not constitute unreasonably small capital, and neither the Parent nor Sellers will have unreasonably small capital, and Parent and Sellers will have sufficient capital with which to conduct its business and/or to wind up its affairs and dissolve, and (iii) there will be no pending or threatened litigation or final judgments against Parent or Sellers in any action for money damages that is reasonably anticipated to be rendered at a time when, or in amounts such that, Parent or Sellers will be unable to satisfy any such judgments promptly in accordance with their terms (taking into account the maximum probable amount of such judgments in any such actions and the earliest reasonable time at which such judgments might be rendered). The cash available to Parent and Sellers, after taking into account all other anticipated uses of the cash of Parent and Sellers, will be sufficient to pay all such judgments promptly in accordance with their terms to the extent such judgments, if any, are in excess of available insurance proceeds. As used in this Section, (x) “insolvent” means, for any person or entity, that the sum of the present fair saleable value of its assets does not and/or will not exceed its debts and other probable liabilities, and (y) the term “debts” includes any legal liability, whether matured or unmatured, liquidated or unliquidated, absolute, fixed or contingent, disputed or undisputed or secured or unsecured.

2.1.13 Environmental Matters . (a) To the knowledge of any of Parent or Sellers:

2.1.13.1 There are no currently pending or threatened written notices of violations, noncompliance, or similar notifications relating to environmental or health or safety matters affecting the Real Property;

2.1.13.2 There are no underground storage tanks or other underground containers of any kind on the Real Property;

2.1.13.3 There are no claims, pending or threatened, by any person relating to or arising out of the environmental conditions of the Real Property and no such claims have been made or threatened in the last five years;

2.1.13.4 There are no judgments, decrees, orders, arrangements or other agreements in any way related to the investigation, cleanup, remediation or removal of any hazardous material related to the Real Property.

(b) Parent and Sellers have provided to Buyer copies of all environmental audits, assessments or other evaluations, if any, known to (and in the possession of) Parent or one or more Sellers and related to the Real Property.

2.1.14 All Material Contracts . To the knowledge of Parent and Sellers, the Purchased Contracts are all of the contracts material to the ownership, operation and use of the Assets except for the contracts listed on Schedule 4.1.6 .

2.2 Representations and Warranties of Buyer and Patterson . Buyer and Patterson, jointly and severally as of the date hereof and as of the Closing Date, represent and warrant to each of the Parent and Sellers as follows:

2.2.1 Organization and Good Standing . Buyer is a limited liability limited partnership duly organized, validly existing under the laws of the State of Delaware, has full requisite corporate power and authority to carry on its business as it is currently conducted, and to own and operate the properties currently owned and operated by it, and is duly qualified or licensed to do business and is in good standing as a foreign corporation authorized to do business in all jurisdictions in which the character of the properties owned or the nature of the business conducted by it would make such qualification or licensing necessary except where the failure to be so qualified or licensed would not have a Material Adverse Effect.

2.2.2 Agreement Authorized and its Effect on Other Obligations . Each of the Buyer and Patterson has the legal capacity and requisite power and authority to enter into and perform its obligations under this Agreement. The consummation of the transactions contemplated hereby have been duly and validly authorized by all necessary corporate action on the part of each of the Buyer and Patterson, and this Agreement is a valid and binding obligation of each of the Buyer and Patterson enforceable against each of the Buyer and Patterson in accordance with its terms. The execution, delivery and performance of this Agreement by each of the Buyer and Patterson will not conflict with

or result in a violation or breach of any term or provision of, or constitute a default under (a) the organizational documents of any of the Buyer and Patterson, (b) any obligation, indenture, mortgage, deed of trust, lease, contract or other agreement to which any of the Buyer and Patterson or any of their respective properties are bound; or (iii) any requirement of statute, law, regulation, judgment, decree or order of any governmental authority or judicial body.

2.2.3 Investigations; Litigation . Except as required by HSR, no investigation or review by any governmental entity with respect to Buyer in connection with any of the transactions contemplated by this Agreement is pending or, to the best of Buyer’s knowledge, threatened, nor has any governmental entity indicated to Buyer an intention to conduct the same.

2.2.4 Consents and Approvals . Except for written notification to Patterson’s lenders and as required by HSR, no consent, approval or authorization of, or filing of a registration with, any governmental or regulatory authority, or any other person or entity is required to be made or obtained by Buyer in connection with the execution, delivery or performance of this Agreement or the consummation of the transactions contemplated hereby.

2.2.5 Finder’s Fee . All negotiations relative to this Agreement and the transactions contemplated hereby have been carried on by the Buyer and its counsel directly with the Sellers and their counsel without the intervention of any other person in such a manner as to give rise to any valid claim against any of the parties hereto for a brokerage commission, finder’s fee or any similar payments.

ARTICLE 3

OBLIGATIONS PENDING CLOSING DATE

3.1 Agreements of Parent and Sellers . Each of the Sellers agrees, unless it obtains the written consent of Buyer, that from the date hereof to the Closing Date, it will, and Parent agrees to cause the Sellers to:

3.1.1 Maintenance of Present Business . Operate its business only in the usual, regular, and ordinary manner so as to maintain the goodwill it now enjoys and, to the extent consistent with such operation, use all reasonable efforts to preserve intact its relationships with customers, suppliers, jobbers, distributors and others having business dealings with it;

3.1.2 No Sale . Not transfer, sell or otherwise convey or dispose of any Asset.

3.1.3 Maintenance of Assets . Make no material change in the Assets and at its expense, maintain all of the Assets in customary repair, order, and condition, reasonable wear and tear excepted;

3.1.4 Purchased Contracts . Comply with the Purchased Contracts and, other than in the ordinary course of business and consistent with past practices, not amend or

modify any Purchased Contract; provided that no such amendment or modification shall extend a Purchased Contract for more than thirty days beyond the later of the Closing Date or the termination date specifically stated therein on the date hereof or change any provision thereof relating to termination or the right to terminate.

3.1.5 Compliance with Law . Duly comply in all material respects with all laws applicable to it and to the conduct of its business;

3.1.6 Inspection . Permit the Buyer and its officers and authorized representatives, during normal business hours, to inspect its records and to consult with its officers, employees, attorneys, and agents for the purpose of determining the accuracy of the representations and warranties hereinabove made and the compliance with covenants contained in this Agreement. Sellers will also furnish to Buyer copies of all manuals and maintenance and similar records in Sellers’ possession or control relating to the Assets. Buyer agrees that it and its officers and representatives shall hold all data and information obtained with respect to the Sellers in confidence in accordance with the terms of the Confidentiality Agreement previously entered into by Buyer and the Sellers, and Buyer further agrees that it will not use such data or information or disclose the same to others, except to the extent such data or information either are, or become, published or a matter of public knowledge.

3.1.7 No New Contracts . Not enter into any new contracts or agreements related to the Assets, except contracts to drill on a daywork basis entered into in the ordinary course of business, consistent with past practices and with terms not lasting more than 30 days.

3.1.8 Notice of Changes . Promptly notify Buyer of any change in circumstances that would make any representation or warranty untrue if such circumstances existed on the date of execution of this Agreement.

3.1.9 Maintenance of Insurance . Maintain the current insurance upon all the Assets.

3.2 Supplemental Information . The parties acknowledge and agree that Sellers shall have the continuing right until the Closing Date to provide Buyer promptly with such additional supplemental information of which Sellers become aware after the date of this Agreement (collectively, the “Supplemental Information”) in the form of (i) amendments to then existing schedules to this Agreement (“Schedules”) or (ii) additional Schedules, as would be necessary to make each of those representations and warranties true and correct as of the Closing Date; provided, however, that Buyer shall be entitled to use such Supplemental Information so provided to determine with respect to all representations and warranties if a Material Adverse Effect has occurred.

3.3 Regulatory and Other Authorizations . Each party hereto agrees to use its reasonable best efforts to obtain all authorizations, consents, orders and approvals of federal, state, local and foreign regulatory bodies and officials and non-governmental third parties that may be or become necessary for its execution and delivery of, and the performance of its

obligations pursuant to, this Agreement, and each party will cooperate fully with the other parties in promptly seeking to obtain all such authorizations, consents, orders and approvals. Without limitation, each of the Sellers and the Buyer shall make an appropriate filing of a Notification and Report Form pursuant to HSR within five business days of the execution and delivery of this Agreement. Each such filing shall request early termination of the waiting period imposed by HSR. Nothing herein shall be construed to require any of Parent, Sellers, Buyers or Patterson to agree to any divestiture of assets or limitations on its operations.

ARTICLE 4

CONDITIONS PRECEDENT TO OBLIGATIONS

4.1 Conditions Precedent to Obligations of Buyer . The obligation of Buyer to consummate and effect the transactions hereunder shall be subject to the satisfaction of the following conditions, or to the waiver thereof by Buyer in the manner contemplated by Section 5.4 hereof before the Closing Date.

4.1.1 Representations and Warranties of each of the Parent and Sellers True at the Closing Date . The representations and warranties of each of the Parent and Sellers herein contained shall be true as of and at the Closing Date with the same effect as though made at such date, except (i) as affected by transactions permitted or contemplated by this Agreement, and (ii) for breaches of such representations and warranties which in the aggregate would not be reasonably likely to result in a Material Adverse Effect on the Assets; each of the Sellers shall have performed or complied in all material respects with all agreements and covenants required by this Agreement to be performed or complied with by each of the Sellers before the Closing Date; and each of the Sellers shall have delivered to the Buyer a certificate dated the Closing Date and signed by its respective chief executive officer or its president and by its chief financial officer or accounting officer and its secretary to both such effects.

4.1.2 No Material Litigation . No suit, action or other proceeding shall be pending or, to any of the Parent’s or Sellers’ knowledge, threatened before any court or governmental agency in which it will be or it is sought to restrain or prohibit or to obtain damages or other relief in connection with this Agreement or the consummation of the transactions contemplated hereby.

4.1.3 Consent of Certain Parties in Privity with the Sellers . The parties to any Purchased Contracts, the holders of any material indebtedness of either of the Sellers, the lessors of any material property leased by either of the Sellers and any other material agreements to which either of the Sellers as a party shall, to the extent necessary in the reasonable opinion of the Buyer, have consented to the transactions contemplated hereby.

4.1.4 HSR . All waiting periods required by HSR shall have expired with respect to the transactions contemplated by this Agreement or early termination with respect thereto shall have been obtained. In addition, any approvals required under any state laws comparable to HSR shall have been obtained.

4.1.5 Secretary’s Certificates . Each of the Sellers shall deliver a secretary’s certificate, which certificate shall have all corporate, partnership and charter documents, as applicable, of such Seller attached thereto and attesting to: (i) the due organization of such Seller; (ii) the due authorization of the transactions contemplated by this Agreement; and (iii) all corporate, partnership or other resolutions adopted by such Seller in connection with the transactions contemplated by this Agreement.

4.1.6 Termination of Leases . The leases related to the Assets (all of which are described in Schedule 4.1.6 ) shall have been terminated in such a manner so that the Seller shall own the Assets subject thereto free and clear of the terms of such leases.

4.2 Conditions Precedent to Obligations of Sellers . The obligations of the Sellers to consummate and effect the transactions hereunder shall be subject to the satisfaction of the following conditions, or to the waiver thereof by the Sellers in the manner contemplated by Section 5.4 before the Closing Date.

4.2.1 Representations and Warranties of the Buyer True at the Closing Date . The representations and warranties of the Buyer herein contained shall be true as of and at the Closing Date with the same effect as though made at such date, except (i) as affected by transactions permitted or contemplated by this Agreement, and (ii) which breaches of such representations and warranties in the aggregate would not be reasonably likely to result in a Material Adverse Effect; the Buyer shall have performed or complied in all material respects with all agreements and covenants required by this Agreement to be performed or complied with by the Buyer on or before the Closing Date; and the Buyer shall have delivered to each of the Sellers a certificate dated the Closing Date and signed by its chief executive officer or its president and by its chief financial officer or accounting officer and its secretary to both such effects.

4.2.2 No Material Litigation . No suit, action or other proceeding shall be pending or, to the Buyer’s knowledge, threatened before any court or governmental agency in which it will be or it is sought to restrain or prohibit or to obtain damages or other relief in connection with this Agreement or the consummation of the transactions contemplated hereby.

4.2.3 HSR . All waiting periods required by HSR shall have expired with respect to the transactions contemplated by this Agreement or early termination with respect thereto shall have been obtained. In addition, any approvals required under any state laws comparable to HSR shall have been obtained

4.2.4 Secretary’s Certificates . Buyer shall deliver a secretary’s certificate, which certificate shall have all corporate and charter documents of Buyer attached thereto and attesting to: (i) the due organization of the Buyer; (ii) the due authorization of the transactions contemplated by this Agreement; and (iii) all corporate or other resolutions adopted by Buyer in connection with the transactions contemplated by this Agreement.

ARTICLE 5

TERMINATION AND ABANDONMENT

5.1 Termination . Anything contained in this Agreement to the contrary notwithstanding, this Agreement may be terminated at any time before the Closing Date:

5.1.1 By Mutual Consent . By mutual written consent of Buyer and each of the Sellers.

5.1.2 By the Buyer Because of Conditions Precedent . By the Buyer, if any condition set forth in Section 4.1 hereof cannot be met and has not been waived, notwithstanding any investigation made by or on behalf of the Buyer.

5.1.3 By Sellers Because of Conditions Precedent . By Sellers, if any condition set forth in Section 4.2 hereof cannot be met and has not been waived, notwithstanding any investigation made by or on behalf of Sellers.

5.1.4 By Buyer Because of Material Adverse Effect . By Buyer, if there has been a Material Adverse Effect on the Assets since the date hereof.

5.1.5 By Buyer or the Sellers Because of Legal Proceedings . By Buyer or the Sellers if any suit, action, or other proceeding shall be pending or threatened by the federal or a state government before any court or governmental agency, in which it is sought to restrain, prohibit, or otherwise affect the consummation of the transactions contemplated hereby.

5.1.6 By Buyer or the Sellers if Transaction is not Effective . By Buyer or the Sellers if the transactions contemplated hereby shall not have become effective on or before the expiration of the 10 ^th business day following termination of the HSR review period.

5.2 Termination by Board of Directors . An election of Buyer or the Sellers to terminate this Agreement shall be exercised on behalf of Buyer or the Sellers by its board of directors or similar governing authority.

5.3 Effect of Termination . In the event of the termination and abandonment of this Agreement pursuant to and in accordance with the provisions of Section 5.1 hereof, this Agreement shall become void and have no force or effect, without any liability on the part of any party hereto (or the stockholders, partners or controlling persons or directors or officers of any party hereto); provided the foregoing shall not relieve any party hereto from any liability for damages incurred as a result of a breach by such party of its representations, warranties, covenants and agreements hereunder occurring before such termination.

5.4 Waiver of Conditions . Subject to the requirements of any applicable law, any of the terms or conditions of this Agreement may be waived at any time by the party that is entitled to the benefit thereof, by action taken by its board of directors, its general partner, the executive

committee of its board of directors or its chief executive officer. No waiver of a particular term or condition of this Agreement shall constitute a waiver of any other term or condition.

ARTICLE 6

ADDITIONAL AGREEMENTS

6.1 Employees . Schedule 6.1 hereto is a complete and accurate listing of all employees of each of the Sellers that devote their full time and effort in the operation of the Assets (the “Employees”). Each of the Sellers will use its reasonable efforts to make all of its Employees available for hire by the Buyer or its affiliates, and the Buyer agrees to hire all of such Employees (other than the Employees listed on Schedule 6.1(a) ) on the Closing Date, subject to such Employees meeting Buyer’s standard employment eligibility requirements and mutual agreement between such Employees and Buyer as to their compensation levels. All such Employees hired by the Buyer are herein referred to as the “Transferred Employees”. Buyer shall have no liability or obligation with respect to the compensation of any Employee or any employee benefits of any Employee, including without limitation, any bonuses, health benefits or IRA contributions, except for (i) the compensation and those benefits that accrue pursuant to such Employees’ employment with Buyer after the Closing Date and (ii) the Retention Bonuses. Each of the Sellers shall cooperate with the Buyer in connection with any offer of employment from the Buyer to the Employees and use their reasonable efforts to cause the acceptance of any and all such offers. Notwithstanding any other provisions of this Agreement, this Section 6.1 shall not be deemed to create any right or claim for the benefit of, and shall not be enforceable by, any person that is not a party to this Agreement.

6.2 Trademarks . The Buyer shall, within 30 days of the Closing Date, remove or cover over all trademarks, trade-names and other marks associated with the Sellers or their affiliates on the Assets and will refrain from using any of such intellectual property for any purpose.

6.3 Further Assurances . From time to time, as and when requested by any party hereto, any other party hereto shall execute and deliver, or cause to be executed and delivered, such documents and instruments and shall take, or cause to be taken, such further or other actions as may be reasonably necessary to effect the transactions contemplated hereby.

6.4 Public Announcements . Except as mutually agreed or as may be required by applicable law, neither Buyer or the Sellers, nor any of their respective affiliates or agents shall issue any press release or public announcement regarding the execution of this Agreement or the transactions contemplated thereby.

6.5 No Solicitation . Parent and Sellers agree that for a period of one year after the Closing that they will not and will cause their affiliates not to solicit for hire any person employed by Buyer in connection with the ownership, use or operation of the Assets.

6.6 Taking Possession of Certain Assets . The Buyer and Sellers acknowledge that some of the Assets will be located on the Sellers’ premises on the Closing Date. The Sellers hereby grant the Buyer a noncancellable license to use the Sellers’ premises on which such

Assets are located as of the Closing Date for the storage of such Assets for a period not to exceed 30 days from the Closing Date, during which time the Buyer will make arrangements for taking possession of such Assets and removing them from the Sellers’ premises. During such 30 day period, the Sellers will make the Assets stored on Sellers’ premises available to Buyer during normal business hours. The removal of such Assets from the Buyer’s premises shall be at the Buyer’s sole cost, expense and risk. The license granted hereunder is in consideration of the Purchase Price and the representations, warranties and covenants of the Buyer hereunder, and no separate compensation shall be paid to the Seller for the granting of such license.

6.7 Payment of Sales Taxes . Buyer shall pay any applicable sales or use taxes that apply to its purchase of the Assets directly to the appropriate taxing authority.

6.8 Termination of Leases . The Parent and Sellers shall take all action necessary to terminate all the leases related to the Assets including those identified on Schedule 4.1.6 , so as to satisfy the condition to Closing set forth in Section 4.1.6 .

6.9 Environmental Inspection . Parent and Sellers agree to give to Buyer, its employees and agents access to the Real Property and all records related thereto so that Buyer can conduct, itself or through its agents, a Phase I environmental study on the Real Property. Upon completion of the study and receipt of the report by Buyer, if Buyer determines in the exercise of its sole judgment that the acquisition of any or all of the Real Property creates a risk to Buyer of liability, cleanup costs or other obligations related to the condition of the Real Property, Buyer may exclude such Real Property from the Assets; provided however, that the Buyer’s election to exclude any or all of such Real Property shall not reduce the Purchase Price.

6.10 WARN Act . Buyer shall be liable for any liability and notice requirement, if any, under the Workers Adjustment Retraining and Notification Act (and the rules and regulations promulgated thereunder) with respect to any Transferred Employee from and after the Closing Date. During the six month period following the Closing Date, Sellers shall give notice of the termination, by the close of business on the date of such termination, of any Employee that is not a Transferred Employee who before the Closing Date worked at Yards 106 and 108 as identified on Schedule 6.1 . During the six month period following the Closing Date, Buyer shall give notice of the termination, by the close of business on the date of termination, of any Transferred Employee working at Yards 106 and 108 as identified on Schedule 6.1 .

6.11 Closing in the Event of HSR Early Termination . In the event that the parties receive notice of the early termination of the HSR waiting period on or before December 27, 2004, the parties will use reasonable commercial efforts to cause the Closing to occur on or before December 31, 2004.

ARTICLE 7

INDEMNIFICATION

7.1 Indemnification by each of the Parent and Sellers . The Buyer and its affiliates, officers, directors, employees, agents, partners and stockholders (collectively, the “Buyer Indemnified Parties”), shall be indemnified by each of the Parent and Sellers jointly and

severally against and with respect to any and all claims, costs, damages, losses, expenses, obligations, liabilities, recoveries, suits, causes of action and deficiencies, including interest, fines, penalties and reasonable fees and expenses of attorneys, consultants and experts (collectively, the “Damages”) that the Buyer Indemnified Parties shall incur or suffer, which arise, result from or relate to (i) any breach by Parent or any of the Sellers of their representations or warranties under or pursuant to this Agreement; (ii) any breach of any material covenant or agreement in this Agreement; (iii) the interference with the use and operation of the Assets as a result of the Ector County tax assessment referred to in Schedule 2.1.3 ; or (iii) the Retained Liabilities.

7.2 Indemnification by Patterson and Buyer . Each of the Sellers and their affiliates, officers, directors, employees, agents, partners and stockholders (collectively, the “Sellers’ Indemnified Parties”) shall be indemnified by Patterson and Buyer against any and all Damages that the Sellers’ Indemnified Parties shall incur or suffer, which arise, result from or relate to (i) any breach of any of Patterson and Buyer’s representations or warranties under or pursuant to of this Agreement; (ii) any breach of any material covenant or agreement in this Agreement; (iii) a failure of Buyer to pay any Taxes that Buyer is required to pay pursuant to Section 6.7 ; (iv) any liability arising pursuant to the Buyer’s obligations under Section 6.10 or (iv) the Assumed Liabilities.

7.3 Indemnification Procedure . If any party hereto discovers or otherwise becomes aware of an indemnification claim arising under Sections 7.1 or 7.2 of this Agreement, such indemnified party shall give written notice to the indemnifying party, specifying such claim, and may thereafter exercise any remedies available to such party under this Agreement; provided, however , that the failure of any indemnified party to give notice as provided herein shall not relieve the indemnifying party of any obligations hereunder, to the extent the indemnifying party is not materially prejudiced thereby. Further, promptly after receipt by an indemnified party hereunder of written notice of the commencement of any action or proceeding with respect to which a claim for indemnification may be made pursuant to Sections 7.1 or 7.2 hereof, such indemnified party shall, if a claim in respect thereof is to be made against any indemnifying party, give written notice to the latter of the commencement of such action; provided, however , that the failure of any indemnified party to give notice as provided herein shall not relieve the indemnifying party of any obligations hereunder, to the extent the indemnifying party is not materially prejudiced thereby. In case any such action is brought against an indemnified party, the indemnifying party shall be entitled to participate in and to assume the defense thereof, jointly with any other indemnifying party similarly notified, to the extent that it may wish, with counsel reasonably satisfactory to such indemnified party, and after such notice from the indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party shall not be liable to such indemnified party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof unless the indemnifying party has failed to assume the defense of such claim and to employ counsel reasonably satisfactory to such indemnified person. An indemnifying party who elects not to assume the defense of a claim shall not be liable for the fees and expenses of more than one counsel in any single jurisdiction for all parties indemnified by such indemnifying party with respect to such claim or with respect to claims separate but similar or related in the same jurisdiction arising out of the same general allegations. Notwithstanding any of the foregoing to the contrary, the indemnified party will be entitled to select its own counsel and assume the

defense of any action brought against it if the indemnifying party fails to select counsel reasonably satisfactory to the indemnified party, the expenses of such defense to be paid by the indemnifying party. No indemnifying party shall consent to entry of any judgment or enter into any settlement with respect to a claim without the consent of the indemnified party, which consent shall not be unreasonably withheld, or unless such judgment or settlement includes as an unconditional term thereof the giving by the claimant or plaintiff to such indemnified party of a release from all liability with respect to such claim. No indemnified party shall consent to entry of any judgment or enter into any settlement of any such action, the defense of which has been assumed by an indemnifying party, without the consent of such indemnifying party, which consent shall not be unreasonably withheld or delayed.

7.4 Limitation on Damages . Notwithstanding anything in this Agreement to the contrary, neither Parent nor Sellers shall be liable to any of the Buyer Indemnified Parties and neither Patterson nor Buyer shall be liable to any of the Seller Indemnified Parties for the cumulative costs of any Damages suffered or incurred by the Buyer Indemnified Parties or the Seller Indemnified Parties, as the case may be, as a result of a breach of a representation or warranty under or pursuant to this Agreement until the Liability Exception (hereinafter and defined) is exceeded; provided however , that to the extent there are Damages, suffered or incurred arising out of one or more events, equal to the Liability Exception, then the party entitled to indemnification shall be indemnified for the total amount of such Damages. The aggregate amount of any Damages owed by Parent or the Sellers, collectively, to the Buyer Indemnified Parties or by Patterson or Buyer, collectively, to the Seller Indemnified Parties, shall not exceed the Purchase Price.

7.5 Liability Exception . For purposes of this Section, the term “Liability Exception” means $100,000.

7.6 Exclusive Remedy . From and after the date hereof, the indemnification under Sections 7.1 and 7.2 shall be the exclusive remedies for monetary damages that may be asserted under this Agreement or in connection with the transactions contemplated herein. In addition, indemnification under Sections 7.1 and 7.2 in connection with a breach of a representation or warranty shall be available only if such representation or warranty was not true as of the Closing Date. Notwithstanding any provision of the contrary contained herein, each of the parties to this Agreement hereby waives any right to recover special, punitive or exemplary damages for any claim asserted against the other; provided that this shall not limit the right of an Indemnified Party to recover special, punitive or exemplary damages payable to a third party for which the Indemnified Party is entitled to indemnity hereunder. Nothing in this Section 7.6 shall limit the availability of equitable remedies, such as specific performance, to enforce the provisions of this Agreement.

ARTICLE 8

MISCELLANEOUS

8.1 Materiality . “Material Adverse Effect” when used in this Agreement, shall mean any material adverse effect on the business, operations, assets or financial condition, or results of

operations of the party or parties at issue or on a parties ability to consummate its obligations as contemplated by this Agreement.

8.2 Survival of Representations, Warranties and Covenants . All representations, warranties, covenants and agreements made by the parties hereto shall terminate 18 months following the Closing Date, except as to the representations and warranties contained in (i) Section 2.1.3 (“Taxes”), which shall continue and survive for the full period of the applicable statute of limitations (giving effect to any waiver or extension thereof); (ii) Section 2.1.4 with respect to title to the Assets, which shall continue and survive indefinitely; and (iii) Section 2.1.5 with respect to inspection of the Assets and limitations on the Sellers’ warranties with respect thereto, which shall continue and survive indefinitely. All claims for indemnification by any party hereto with respect to a breach of a representation or warranty must be asserted in writing with specificity before the expiration of the applicable survival period.

8.3 Entirety . This Agreement embodies the entire agreement among the parties with respect to the subject matter hereof, and all prior agreements between the parties with respect thereto are hereby superseded in their entirety.

8.4 Counterparts . Any number of counterparts of this Agreement may be executed and each such counterpart shall be deemed to be an original instrument, but all such counterparts together shall constitute but one instrument.

8.5 Notices and Waivers . Any notice or waiver to be given to any party hereto shall be in writing and shall be delivered by courier, sent by facsimile transmission or first class registered or certified mail, postage prepaid, return receipt requested:


	If to Sellers:

Addressed to:		With a copy to:

Key Energy Services, Inc.		Porter & Hedges, L.L.P.
6 Desta Drive		700 Louisiana, 35th Floor
Midland, Texas 79705		Houston, Texas 77210-4744
Attn: General Counsel		Attn: Samuel N. Allen
Facsimile: (432) 571-7537		Facsimile: (713) 226-0229

	If to Buyer:

Addressed to:		With a copy to:

Patterson-UTI Energy, Inc.		Fulbright & Jaworski L.L.P.
4510 Lamesa Highway		1301 McKinney, Suite 5100
P. O. Box Drawer 1416		Houston, TX 77010-3095
Snyder, Texas 79549		Attention: Michael W. Conlon
Attention: Chief Executive Officer		Telephone: (713) 651-5427
Telephone (325) 574-6300		Facsimile: (713) 651-5246
Facsimile (325) 574-6307

Any communication so addressed and mailed by first-class registered or certified mail, postage prepaid, with return receipt requested, shall be deemed to be received on the third business day after so mailed, and if delivered by courier or facsimile to such address, upon delivery during normal business hours on any business day.

8.6 Limitations on Assignment . Notwithstanding any other provision hereof, this Agreement shall neither constitute nor require an assignment by Sellers of any Purchased Contract or other right if any attempted assignment of the same without the consent of any party would constitute a breach thereof or a violation of any law or any judgment, decree, order, writ, injunction, rule or regulation of any governmental entity unless and until such consent shall have been obtained. In the case of any such Purchased Contract that cannot be effectively transferred to Buyer without such consent (a “Consent Required Contract”), the Sellers agree that between the date hereof and the Closing Date they will use their reasonable commercial efforts to obtain or cause to be obtained the necessary consents to the transfer of Consent Required Contract. In the event that the Sellers shall have failed prior to the Closing Date to obtain consents to the transfer of Consent Required Contract and Buyer shall have waived the conditions set forth in Section 4.1.3 , the terms of this Section 8.6 shall govern the transfer of the benefits of each Consent Required Contract. The Sellers and Buyer shall use their reasonable commercial efforts after the Closing Date to obtain any required consent to the assignment to, and assumption by, Buyer of such Consent Required Contract that is not transferred to Buyer at the Closing (a “Nonassigned Contract”). With respect to the Nonassigned Contracts that are not assignable by the terms thereof or for which consents to the assignment thereof cannot be obtained as provided herein, such Nonassigned Contracts shall be held by Sellers in trust for Buyer and after the Closing Date shall be performed by Buyer in the name of Sellers, at Buyer’s sole cost, risk and expense, and all benefits and obligations derived thereunder shall be for the account of Buyer; provided, however, that where entitlement of Buyer to such Nonassigned Contracts hereunder is not recognized by any third party, such Sellers shall, at the request of Buyer, enforce in a reasonable manner, at the cost of and for the account of Buyer, any and all rights of the Sellers against such third party. Buyer shall indemnify Sellers in respect of Buyer’s performance or failure to perform any obligation, duty or liability in connection with such Nonassigned Contracts.

8.7 No Negotiation . Until such time, if any, as this Agreement is terminated pursuant to Article 5 , Parent and Sellers will not, nor will any of them permit any of their respective representatives to, directly or indirectly, solicit, initiate or encourage any inquiries, offers or proposals from, discuss or negotiate with or execute any agreement with or provide any information to, any person or entity (other than Purchaser) relating to any transaction involving the sale of the Assets or of any of the capital stock or any other equity securities of Sellers, or any merger, consolidation, business combination, liquidation, recapitalization, dissolution or similar transaction involving Sellers (collectively, “Sale Proposals”), or any other transaction the consummation of which would or could reasonably be expected to impede, interfere with, prevent or materially delay the transactions contemplated by this Agreement or that could reasonably be expected to materially dilute the benefits to Purchaser of the transactions contemplated by this Agreement. If any such inquiries or Sale Proposals are received by, or any such information is requested from or any such negotiations or discussions are sought to be initiated with, Parent or Sellers, then Parent and Sellers will promptly notify Purchaser of the

nature, terms and status of the foregoing and the identity of the inquiring party and provide Purchaser with a copy of all written materials provided in connection with such Sale Proposal. Until such time, if any, as this Agreement is terminated pursuant to Article 5 , neither Parent nor Sellers will accept any Sale Proposal from any Person or entity other than Purchaser.

8.8 Convenience of Forum; Consent to Jurisdiction . The parties to this Agreement hereby consent to and subject themselves to the jurisdiction of the United States District Court for the Southern District of Texas, and in the event such court is not available to the parties, to the courts of the State of Texas located in Harris County, Texas, with respect to any matter arising under this Agreement. Service of process, notices and demands of such courts may be made upon any party to this Agreement by personal service at any place where it may be found or giving notice to such party as provided in this Agreement.

8.9 Enforcement of the Agreement . The parties hereto agree that irreparable damage would occur if any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof, this being in addition to any other remedy to which they are entitled at law or in equity.

8.10 Table of Contents and Captions . The table of contents and captions contained in this Agreement are solely for convenient reference and shall not be deemed to affect the meaning or interpretation of any article, section, or paragraph hereof.

8.11 Successors and Assigns . This Agreement shall be binding upon and shall inure to the benefit of and be enforceable by the successors and assigns of the parties hereto.

8.12 Severability . If any term, provision, covenant or restriction of this Agreement is held by a court of competent jurisdiction to be invalid, void, or unenforceable, the remainder of the terms, provisions, covenants and restrictions shall remain in full force and effect and shall in no way be affected, impaired or invalidated. It is hereby stipulated and declared to be the intention of the parties that they would have executed the remaining terms, provisions, covenants and restrictions without including any of such which may be hereafter declared invalid, void or unenforceable.

8.13 Applicable Law . This Agreement shall be governed by and construed and enforced in accordance with the applicable laws of the State of Texas.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, each of the Parent and Sellers has executed this Agreement, and the Buyer has caused this Agreement to be signed in its name by its duly authorized representative, all as of the day and year first above written.


		BUYER:

		PATTERSON-UTI DRILLING COMPANY LP, LLLP

		By:		Patterson (GP) LLC

		By:		/s/ Jonathan D. Nelson

		Name:		Jonathan D. Nelson

		Title:		VP CFO


		PATTERSON

		PATTERSON-UTI ENERGY, INC.

		By:		/s/ John E. Vollmer III

		Name:		John E. Vollmer III

		Title:		Senior Vice President - Corp Development


		SELLERS:

		KEY ENERGY DRILLING, INC.

		By:		/s/ Richard J. Alario

				Richard J. Alario, Vice President

		KEY ROCKY MOUNTAIN, INC.

		By:		/s/ Richard J. Alario

				Richard J. Alario, Vice President

		KEY FOUR CORNERS, INC.

		By:		/s/ Richard J. Alario

				Richard J. Alario, Vice President


		KEY ENERGY DRILLING BENEFICIAL, L.P.

		By:		Key Energy Drilling, Inc., General Partner

		By:		/s/ Richard J. Alario

				Richard J. Alario, Vice President

		PARENT

		KEY ENERGY SERVICES, INC.

		By:		/s/ Richard J. Alario

				Richard J. Alario, President and Chief Executive Officer

Schedules are omitted in accordance with Item 601(b)(2) of Regulation S-K.

Schedules will be provided by Patterson-UTI Energy, Inc. to the Securities and Exchange Commission upon request.

Exhibit 10.23

Patterson-UTI Energy, Inc.
Letterhead

October 22, 2004

Name
Address

Dear _____________:

This letter confirms and evidences the existing agreement between Patterson-UTI Energy, Inc. (the “Company”) and you pursuant to which the Company agrees to pay to you within ten (10) days of your termination of employment with the Company for any reason (including voluntary termination by you), an amount in cash equal to your annual base salary at the time of such termination. You agree that any payment made pursuant to the agreement evidenced in this letter will reduce dollar for dollar any payment owed to you, if any, pursuant to the Change in Control Agreement dated January 29, 2004 between the Company and you or any agreement in substitution therefore. You agree that this letter agreement evidences and supercedes any oral understanding between the Company and you with respect to the payment of a cash severance payment to you upon your termination.

Please acknowledge your agreement below.


		PATTERSON-UTI ENERGY, INC.

		By:

Acknowledged and Agreed this
___day of October, 2004


Name

Exhibit 10.26

Summary Description of 2003 Cash Bonus Plan

Patterson-UTI’s Compensation Committee determined that Patterson-UTI should implement a formal cash bonus program and created a cash bonus plan for 2003-related performance of a bonus pool for certain employees, including the top executive officers, based on earnings before interest, income taxes and depreciation, depletion and amortization. The Compensation Committee retained the right to allocate the pool among the executive officers and other employees in its discretion. The Compensation Committee determined that a total cash bonus pool of approximately $3.4 million, of which $1.85 million was allocated for executive officers, be established and awarded cash bonuses for fiscal 2003 in April 2004 under the Amended and Restated Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended, to the following persons in the following amounts:


Name and Position	Cash Bonus

Mark S. Siegel	$	411,530
Chairman of the Board

Cloyce A. Talbott	$	411,530
Chief Executive Officer

A. Glenn Patterson	$	411,530
President and Chief Operating Officer

Kenneth N. Berns	$	205,765
Senior Vice President and Director

Jonathan D. Nelson	$	205,765
Vice President,
Chief Financial Officer, Secretary and Treasurer

John E. Vollmer III	$	205,765
Senior Vice President - Corporate Development

TOTAL	$	1,851,885

Exhibit 10.27

Summary Description of Director Compensation

Directors who are also employees of Patterson-UTI do not receive compensation for serving as a director or as a member of a committee of the Board of Directors. All directors are reimbursed for reasonable out-of-pocket expenses incurred in connection with attendance at Board of Directors meetings and committee meetings. Each non-employee director receives annual cash compensation of $35,000. Each non-employee director that serves on the Audit Committee or Compensation Committee receives additional annual cash compensation of $10,000 per committee on which he or she serves, with the chairman of each such committee receiving $15,000.

Patterson-UTI maintains a Non-Employee Director Stock Option Plan (the “Director Plan”). Under the Director Plan, each non-employee director is granted options to purchase 40,000 shares of common stock, $0.01 par value per share, of the Company (the “Common Stock”) upon becoming a director and is granted options to purchase 20,000 shares of Common Stock on the last business day of each subsequent year in which the director serves on the Board of Directors.

Exhibit 21.1

Subsidiaries of the Registrant


		State of
		Incorporation or
Name		organization
Ambar Drilling Fluids LP, LLLP		Delaware
Eastern Reservoir Services Company		Nova Scotia
International Petroleum Services Company		Pennsylvania
Lone Star Mud LP, LLLP		Delaware
Norton Drilling Company Mexico, Inc.		Delaware
Norton Drilling, L.P.		Delaware
Norton Drilling Services, Inc.		Delaware
Norton GP, L.L.C.		Delaware
Patterson (GP) LLC		Delaware
Patterson (GP2) LLC		Delaware
Patterson (LP) LLC		Delaware
Patterson Petroleum LP, LLLP		Delaware
Patterson Petroleum Trading Company LP, LLLP		Delaware
Patterson-UTI Aviation Services, LLC		Delaware
Patterson-UTI Drilling Company LP, LLLP		Delaware
Patterson-UTI Drilling Company South LP, LLLP		Delaware
Patterson-UTI Drilling Company West LP, LLLP		Delaware
Phelps Drilling Co.		Nova Scotia
Suits Drilling Company		Oklahoma
TMBR/Sharp Drilling, LLC		Delaware
Universal Well Services, Inc.		Delaware
UTI Drilling Canada, Inc.		Delaware
UTI Drilling, L.P.		Texas
UTI Management Services, L.P.		Texas
UTICO Hard Rock Boring, Inc.		Delaware
UTICO, Inc.		Delaware

Effective as of January 1, 2005, Patterson-UTI Drilling Company West LP, LLLP was merged into Patterson-UTI Drilling Company South LP, LLLP which changed its name to Patterson-UTI Drilling Company LP, LLLP.

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-47917, 333-39471, 333-67810, 333-60470, 333-60466, 333-101557, 333-97972 and 333-108311), and in the Registration Statement on Form S-3 (No. 333-89885) of Patterson-UTI Energy, Inc. and its subsidiaries of our report dated February 24, 2005 relating to the financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 24, 2005 relating to the financial statement schedules, which appears in this
Form 10-K.

PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2005

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

I hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-47917, 333-39471, 333-67810, 333-60470, 333-60466, 333-101557, 333-97972 and 333-108311) and in the Registration Statement on Form S-3 (No. 333-89885) of Patterson-UTI Energy, Inc. and its subsidiaries of information contained in my summary reserve reports relating to the oil and natural gas reserves as of December 31, 2004, 2003, and 2002, which appears in this Form 10-K.

/s/ M. Brian Wallace

M. BRIAN WALLACE, P.E.

Dallas, Texas
February 24, 2005

EXHIBIT 31.1

CERTIFICATIONS

I, Cloyce A. Talbott, certify that,

1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



	/s/ CLOYCE A. TALBOTT
	Cloyce A. Talbott
	Chief Executive Officer

Date: February 25, 2005

EXHIBIT 31.2

CERTIFICATIONS

I, Jonathan D. Nelson, certify that:

1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc.

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ JONATHAN D. NELSON

Jonathan D. Nelson

Vice President-Finance, Chief Financial Officer, Secretary and Treasurer

Date: February 25, 2005

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NOT FILED PURSUANT TO THE SECURITIES EXCHANGE ACT OF 1934

In connection with the Annual Report of Patterson-UTI Energy, Inc. (the “Company”) on Form 10-K for the period ending December 31, 2004, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Cloyce A. Talbott, Chief Executive Officer, and Jonathan D. Nelson, Chief Financial Officer, of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission upon request.

/s/ Cloyce A. Talbott

Cloyce A. Talbott

Chief Executive Officer

February 25, 2005

/s/ Jonathan D. Nelson

Jonathan D. Nelson

Chief Financial Officer

February 25, 2005

	(a)	the real property and real property leases described on Schedule 1.1(a) hereto (the “Real Property”);

	(b)	the tangible personal property of the Sellers (such as land drilling rigs, drilling components, engines, machinery, spare parts, trucks, transport trailers and equipment associated with any of the foregoing) described on Schedule 1.1(b) hereto;

	(c)	all supplies and other inventory of the Sellers used or held for use in connection with the operation of the property described in Section 1.1(b) ;



	/s/ JONATHAN D. NELSON
	Jonathan D. Nelson
	Vice President-Finance, Chief Financial Officer, Secretary and Treasurer

	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



/s/ Jonathan D. Nelson
Jonathan D. Nelson
Chief Financial Officer
February 25, 2005