August 6, 2013

VIA EDGAR

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

Attention: Brad Skinner

Re: Patterson-UTI Energy, Inc.

Form 10-K for Fiscal year Ended December 31, 2012

Filed February 13, 2013

File No. 000-22664

Dear Mesdames and Sirs:

By letter dated July 23, 2013, Patterson-UTI Energy, Inc. (the “Company”) received the Staff’s comments relating to the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. The following numbered paragraphs repeat the comments for your convenience, followed by our responses to those comments.

Form 10-K for Fiscal Year Ended December 31, 2012

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 24

1. We note your statement on page 25 that “In 2012, however, margins from the pressure pumping segment were lower than in 2011.” Please enhance your discussion to provide clarity on how you define “margins.” With regard to margins, we note your earnings calls generally include a discussion of drilling and pressure pumping margins. Please tell us whether you view margins as a key performance indicator of your business and how you have considered providing analysis of your margin results in your periodic filings.

We respectfully acknowledge the Staff’s comment. We consider revenues and operating income to be our key performance indicators. We use the term “margin,” however, when discussing what we consider to be the component of our earnings most impacted by the variability in our contract drilling and pressure pumping operations. We define “margin” as revenues less direct operating costs. In future filings, we propose including a subtotal for margin in the tables we have customarily included in MD&A. The tables below exemplify how we will present this financial information:

Comparison of the years ended December 31, 2012 and 2011

The following tables summarize operations by business segment for the years ended December 31, 2012 and 2011:

	Year Ended December 31,
Contract Drilling	2012		2011		% Change
	(Dollars in thousands)
Revenues	$	1,821,713	$	1,669,581		9.1	%
Direct operating costs		1,075,491		972,778		10.6	%
Margin		746,222		696,803		7.1	%
Selling, general and administrative		6,513		6,408		1.6	%
Depreciation and impairment		390,316		344,312		13.4	%
Operating income	$	349,393	$	346,083		1.0	%
Operating days		80,833		78,758		2.6	%
Average revenue per operating day	$	22.54	$	21.20		6.3	%
Average direct operating costs per operating day		13.31		12.35		7.8	%
Average margin per operating day	$	9.23	$	8.85		4.3	%
Average rigs operating		221		216		2.3	%
Capital expenditures	$	744,949	$	784,686		(5.1	)%

	Year Ended December 31,
Pressure Pumping	2012			2011			% Change
	(Dollars in thousands)
Revenues	$	841,771		$	845,803			(0.5	)%
Direct operating costs		580,878			561,398			3.5	%
Margin		260,893			284,405			(8.3	)%
Selling, general and administrative		17,036			17,686			(3.7	)%
Depreciation, amortization and impairment		111,062			73,279			51.6	%
Operating income	$	132,795		$	193,440			(31.4	)%
Fracturing jobs		1,229			1,531			(19.7	)%
Other jobs		5,659			7,010			(19.3	)%
Total jobs		6,888			8,541			(19.4	)%
Average revenue per fracturing job	$	590.70		$	467.85			26.3	%
Average revenue per other job	$	20.46		$	18.48			10.7	%
Average revenue per total job	$	122.21		$	99.03			23.4	%
Average direct operating costs per total job		84.33			65.73			28.3	%
Average margin per total job	$	37.88		$	33.30			13.8	%
Margin as a percentage of revenue		31.0	%		33.6	%		(7.7	)%
Capital expenditures	$	194,117		$	198,061			(2.0	)%

Notes to Consolidated Financial Statements

Note 1. Description of Business and Summary of Significant Accounting Policies, page F-8

Oil and natural gas properties, page F-9

2. We note your accounting policy statement that “capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production method, based on engineering estimates of proved oil and natural gas reserves for each respective field.” However, it appears that the types of costs you describe, except for lease acquisition costs, are required to be amortized on the basis of the total estimated units of proved developed reserves. Please confirm, if true, that your policies comply with FASB ASC 932-360-35-6 and 7 and modify your disclosure accordingly, or otherwise advise.

We respectfully acknowledge the Staff’s comment and confirm that our policies with respect to our oil and natural gas properties comply with ASC 932-360-35-6 and 7. We will modify in future filings to clarify our policy as follows:

The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved oil and natural gas reserves for each respective field.

Note 4. Property and Equipment, page F-13

3. We note you evaluated the recoverability of your contract drilling segment as a whole exclusive of rigs tested separately for marketability and your pressure pumping segment as a whole exclusive of equipment reviewed separately for retirement and determined that no triggering event occurred during the periods presented. Nonetheless, a separate analysis performed based on the marketability of your fleet of drilling rigs and pressure pumping equipment resulted in impairment charges of $12.5 million in 2012, $15.7 million in 2011 and $4.2 million in 2010. Given your statement that long-lived assets are evaluated for impairment at the lowest level for which identifiable cash flows can be separated from other long-lived assets, please clarity for us why you appear to perform two separate recoverability tests.

We respectfully acknowledge the Staff’s comment and advise that we do evaluate the recoverability of our long-lived asset groups whenever events or changes in circumstances indicate their carrying value may not be recoverable. We have determined our contract drilling and pressure pumping segments to be the lowest level for which identifiable cash flows are largely independent from other long-lived assets. For the years 2012, 2011 and 2010 there were no triggering events identified for our contract drilling or pressure pumping asset groups.

The impairment charges disclosed in our 2012 Form 10-K and referred to above are asset specific and result from the Company’s assessment of the serviceability of individual pieces of equipment. We frequently deploy multiple pieces of equipment to fulfill the drilling and pressure pumping services we provide to our customers and, for similar items, these assets are largely fungible. However, as part of our normal operations, we must periodically evaluate individual assets and components for operability and/or obsolescence. To the extent we determine that an individual long-lived asset may no longer be serviceable, we charge to expense the remaining undepreciated net carrying value, less any amount of salvage and components that may still

be serviceable. To avoid confusion, we will clarify in future filings by removing “(excluding the rigs which had been removed from the Company’s marketable fleet as discussed below)” and “(excluding the equipment that was retired as discussed below).” The third paragraph of Note 4 would read as follows:

The Company evaluates the recoverability of its long-lived assets whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). In light of levels of activity and revenue per operating day experienced by the Company and its peers in 2010, 2011 and 2012, management concluded that no triggering event had occurred in 2010, 2011 or 2012 with respect to its contract drilling segment as a whole. The Company also concluded that no triggering event occurred with respect to its pressure pumping segment in 2010, 2011 or 2012. With respect to the long-lived assets in the Company’s oil and natural gas exploration and production segment, the Company assesses the recoverability of long-lived assets at the end of each quarter due to revisions in its oil and natural gas reserve estimates and expectations about future commodity prices.

The Company acknowledges that:

• it is responsible for the adequacy and accuracy of the disclosure in the filing;

• Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please do not hesitate to call me at (214) 765-5525 if you have any questions or would like any additional information regarding these matters.

Very truly yours,

/s/ John E. Vollmer III

John E. Vollmer III

Senior Vice President-Corporate Development,

Chief Financial Officer and Treasurer