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Correspondence

November 4, 2015

VIA EDGAR

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

Attention: Ethan Horowitz

		Re:		Patterson-UTI Energy, Inc.
				Form 10-K for Fiscal Year Ended December 31, 2014
				Filed February 12, 2015
				Form 10-Q for Fiscal Quarter Ended June 30, 2015
				Filed July 27, 2015
				File No. 000-22664

Dear Mesdames and Sirs:

By letter dated October 21, 2015, Patterson-UTI Energy, Inc. (the “Company”) received the Staff’s comments relating to the Company’s response to the Staff’s comment letter submitted August 31, 2015, with respect to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015. 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, 2014

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 21

Critical Accounting Policies, page 23

Property and Equipment, page 23

1. The draft disclosure provided in response to prior comment 1 describes the methods and key assumptions used in testing your long-lived assets for impairment. However, it does not appear that you have discussed the degree of uncertainty associated with your key assumptions or addressed potential events that could reasonably be expected to affect these key assumptions. Please revise your disclosure accordingly.

In our quarterly report on Form 10-Q for the fiscal quarter ended September 30, 2015, we provided expanded disclosure regarding our testing of long-lived assets for impairment. Following is an example of the disclosure as it would have appeared in the Form 10-K for the fiscal year ended December 31, 2014:

In light of the significant decline in oil and natural gas commodity prices beginning in the fourth quarter of 2014 and continuing into 2015, we deemed it necessary to assess the recoverability of long-lived asset groups for both contract drilling and pressure pumping. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling and pressure pumping segments. With respect to these assets, future cash flows were estimated over the expected

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remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated. The expected cash flows for the contract drilling segment include the backlog of commitments for contract drilling revenues under term contracts, which was approximately $1.5 billion at December 31, 2014. Rigs not under term contracts are subject to market pricing. Utilization and market rates for rigs and for the pressure pumping segment were estimated based upon our historical experience in prior downturns. Also, the expected cash flows for our contract drilling and pressure pumping segments were based on the assumption that activity levels in both segments will begin to recover in late 2015 and continue to recover in 2016 in response to improved oil prices. This oil price assumption is consistent with forecast information published by the United States Energy Information Administration in January 2015. While we believe our assumptions with respect to future pricing for oil and natural gas were reasonable, actual future prices may vary significantly from the ones that we assumed. The timeframe over which oil and natural gas prices will recover is highly uncertain. Potential events that could affect our assumptions regarding future prices and the timeframe for a recovery are affected by factors such as:

• market supply and demand,

• domestic and international military, political, economic and weather conditions,

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

• legal and other limitations or restrictions on exportation and/or importation of oil and natural gas,

• technical advances affecting energy consumption and production,

• the price and availability of alternative fuels,

• the cost of exploring for, developing, producing and delivering oil and natural gas, and

• regulations regarding the exploration, development, production and delivery of oil and natural gas.

All of these factors are beyond our control. If the current lower oil and natural gas commodity price environment were to last into 2016 and beyond, our actual cash flows would likely be less than the expected cash flows used in this assessment and could result in impairment charges in the future and such impairment could be material. See “Item 1A. Risk Factors - We Are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in Oil and Natural Gas Prices May Adversely Affect Our Operating Results.”

Impairment considerations related to our oil and natural gas segment are discussed below.

2. From your response to prior comment 2, we note that overall rig utilization fell from approximately 89% as of December 31, 2014 to approximately 44% as of June 30, 2015 and utilization for mechanical rigs and other electric rigs was approximately 20% as of June 30, 2015. Your response states that you do not expect any meaningful increase in demand for North American land drilling rigs until oil or natural gas prices improve. In addition, disclosure in your Form 10-Q for the period ended June 30, 2015 states that your industry is experiencing a severe downturn. Please tell us about your impairment analysis as of June 30, 2015 for rigs not currently under contract and address the impact of changes in expected demand for your drilling services. As part of your response, specifically tell us about your assessment of stacked rigs. Refer to FASB ASC 360-10-35.

During the first quarter of 2015, oil prices averaged $48.54 per barrel and reached a low of $43.39 per barrel on March 17, 2015. Oil prices improved during the second quarter of 2015 and averaged $57.85 per barrel. Although a price improvement occurred earlier than we projected, this improvement was generally consistent with our assumption at December 31, 2014, that oil prices would improve late in 2015 and continue to improve in 2016, which would result in improved activity levels for the contract drilling business. During the second quarter of 2015 as oil prices increased, we received requests from customers to reactivate drilling rigs to resume operations in the third quarter of 2015. We believed this was an indication that future activity levels would be improving for the contract drilling business, which was consistent with our expectations at December 31, 2014 and through the first two quarters of 2015. ASC

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360-10-35 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. Market conditions at June 30, 2015 were generally consistent with our assumptions at December 31, 2014, and there was no event or change in circumstances that indicated that the carrying amount of the long-lived assets of the contract drilling business was not recoverable.

During the third quarter of 2015, however, oil prices declined and averaged $46.42 per barrel and reached a new low for 2015 of $38.22 per barrel on August 24, 2015. In response to lower oil prices in the third quarter of 2015, we lowered our expectations with respect to future activity levels in the contract drilling business. In light of our revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the market for contract drilling services during the third quarter of 2015, we deemed it necessary to assess the recoverability of long-lived assets for contract drilling. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling segment. With respect to these assets, future cash flows were estimated over the expected remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated. The expected cash flows for the contract drilling segment were based on our historical experience of utilization and rates in prior downturns. Also, the expected cash flows for the contract drilling segment were based on the assumption that activity levels would begin to recover in the first quarter of 2017 in response to improved oil prices. While we believe these assumptions with respect to future pricing for oil and natural gas were reasonable, actual future prices may vary significantly from the ones that we assumed. The timeframe over which oil and natural gas prices will recover is highly uncertain.

On a periodic basis, at least annually, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive (“stacked”) rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional, vertical wells versus drilling longer, horizontal wells using higher specification rigs). The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs will be retired. In the quarter ended September 30, 2015, we identified 24 mechanical rigs and 9 non-APEX^® electric rigs that will no longer be marketed. Also, we had 15 additional mechanical rigs that were not operating. Although these 15 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to higher specification drilling rigs. We recorded a charge of $131 million related to the retirement of the 33 rigs, the 15 mechanical rigs that remain marketable but were not operating, and the write-down of excess spare rig components to their realizable values.

Goodwill, page 24

3. As noted in your response to prior comment 3, your market capitalization was less than total stockholders’ equity as of December 31, 2014. However, a control premium was deemed to be reasonable in assessing your enterprise value. Please tell us about the qualitative and quantitative factors considered in determining the control premium applied as part of this assessment and explain the characteristics of the control premium used in your analysis.

Control premiums are common in acquisitions in the oil field service industry. We reviewed the implied premiums in acquisitions that we believed to be relevant and were in the oil field service or related industries. The control premiums in those transactions ranged from 32% to 50% of the pre-announcement share values. The transactions that were considered are listed in Exhibit 1 to this letter. While the observed range of control premiums was 32% to 50%, our analysis required the use of a control premium of only 20% to result in an implied enterprise value in excess of total stockholders’ equity.

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4. Please explain how you concluded that your contract drilling segment represents a reporting unit pursuant to FASB ASC 350-20-35-34. As part of your response, tell us how you considered other approaches to determining your reporting units (e.g., based on rig classification – APEX rigs, other electric rigs, and mechanical rigs).

FASB ASC 350-20-35-34 states: “A component of an operating segment is a reporting unit if the component constitutes a business or a nonprofit activity for which discrete financial information is available and segment management, as that term is defined in paragraph 280-10-50-7, regularly reviews the operating results of that component.”

FASB ASC 280-10-50-7 states: “Generally, an operating segment has a segment manager who is directly accountable to and maintains regular contact with the chief operating decision maker to discuss operating activities, financial results, forecasts, or plans for the segment. The term segment manager identifies a function, not necessarily a manager with a specific title.”

Drilling rigs are equipped with engines, a drawworks, a mast, pumps to circulate drilling fluid, blowout preventers, drill pipe and related equipment. Their power source is either electric or mechanical. The majority of rig components are interchangeable between mechanical rigs and electric rigs. Drilling rigs with the same capacity components, regardless of their power source, are capable of drilling the same wells, including both vertical and horizontal wells. Additionally, all of our drilling rigs are mobile both within and across geographic areas within North America.

Individual rigs are managed by Rig Managers that report to Superintendents who manage a group of rigs. Rigs are typically assigned to Superintendents based upon the rig location and without regard to the rig’s classification as APEX^®, other electric or mechanical, or other specifications of the rig. If a rig is relocated to a geographic area outside of the assigned Superintendent’s region, the rig is reassigned to a Superintendent in the rig’s new region. The geographic relocation of drilling rigs occurs in response to changes in customer demand.

We believe our contract drilling segment is a reporting unit and that the President of this segment is the segment manager. This person is directly accountable to and maintains regular contact with our chief operating decision maker to discuss operating activities, financial results, forecasts, or plans for the segment. Also, within the contract drilling segment, all Superintendents ultimately report to the segment President. Management of the contract drilling segment, including the segment President, regularly reviews drilling segment operating results, with a focus on individual rig and customer contract performance.

Given the factors described above, we do not believe that separating reporting units by rig classification would be appropriate.

5. We note that you concluded that it was more likely than not that the fair values of your reporting units were greater than their carrying amounts as of December 31, 2014 based on the factors identified in your response to prior comment 3. Please tell us whether recent changes in the environment in which you operate were deemed to be a circumstance requiring the evaluation of goodwill as of June 30, 2015.

As noted in our response to comment 2 above, during the first quarter of 2015, oil prices averaged $48.54 per barrel and reached a low of $43.39 per barrel on March 17, 2015. Oil prices improved during the second quarter of 2015 and averaged $57.85 per barrel. Although a price improvement occurred earlier than we projected, this improvement was generally consistent with our assumption at December 31, 2014, that oil prices would improve in late 2015 and continue to improve in 2016, which would result in improved activity levels for both the contract drilling and pressure pumping businesses. During the second quarter of 2015 as oil prices increased, we received requests from customers to reactivate drilling rigs to resume operations in the third quarter of 2015. We believed this was an indication that future activity levels would be improving for both the contract drilling and pressure pumping businesses, which was consistent with our expectations at December 31, 2014 and through the first two quarters of 2015. Thus, we determined there was no “triggering event” requiring an evaluation of goodwill as of June 30, 2015. During the third quarter of 2015, however, oil prices declined and averaged $46.42 per barrel and reached a

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new low for 2015 of $38.22 per barrel on August 24, 2015. In response to lower oil prices in the third quarter of 2015, we lowered our expectations with respect to future activity levels in both the contract drilling and pressure pumping businesses. In light of our revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the markets for contract drilling and pressure pumping services during the third quarter of 2015, we performed a goodwill impairment test as of September 30, 2015. In completing the first step of the analysis, the fair value of each reporting unit was estimated using both the income and market valuation methods. The estimate of the fair value of each reporting unit required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The inputs included assumptions related to the future performance of our contract drilling and pressure pumping reporting units, such as future oil and natural gas prices and projected demand for our services, and assumptions related to discount rates, long-term growth rates and control premiums.

Based on the results of the first step of the goodwill impairment test as of September 30, 2015, we concluded that no impairment was indicated in our contract drilling reporting unit; however, impairment was indicated in our pressure pumping reporting unit. In the three months ended September 30, 2015, we recognized an impairment charge of $125 million associated with the impairment of the goodwill of the pressure pumping reporting unit. The implied fair value of goodwill was estimated using a variety of valuation methods, including the income and market approaches. The estimate of fair value required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The inputs included assumptions related to the future performance of our pressure pumping reporting unit, such as future oil and natural gas prices and projected demand for our services, and assumptions related to discount rates, long-term growth rates and control premiums.

Form 10-Q for Fiscal Quarter Ended June 30, 2015

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 21

6. Your response to prior comment 4 indicates that you do not consider horsepower to be a key performance indicator for your pressure pumping business. However, disclosure in your periodic Exchange Act filings frequently includes information about the horsepower for your pressure pumping equipment. Also, as noted in our prior comment, you refer to horsepower in discussing your pressure pumping business as part of earnings conference calls. Please explain how horsepower is used as a measure to manage the operations of your pressure pumping business and tell us whether you believe it is a material metric for investors. Refer to section I.B. of SEC Release No. 33-8350.

We believe that the key performance indicators for pressure pumping activity are the number of fracturing jobs and the average revenue per fracturing job that are presented in the tables on pages 28 and 30 of our Form 10-Q for the fiscal quarter ended June 30, 2015 and pages 30 and 32 of our Form 10-Q for the fiscal quarter ended September 30, 2015.

We have 454 frac pumps which represent approximately one million horsepower of fracturing capacity. These pumps are deployed to jobs in groups of pumps based upon the customer’s horsepower requirements for each job. With fewer jobs in this market environment, we have elected to concentrate wear and tear in a smaller number of pieces of equipment by parking (or “stacking”) a portion of the equipment. Alternatively, we could rotate the equipment from job to job and spread the wear and tear evenly over each piece of equipment. Under such a scenario, every piece of equipment could potentially work every week. This parked equipment can be readily deployed to customer locations at current activity levels or as activity levels improve.

The amount of hydraulic horsepower is simply a measure of the operating capacity of the business. While the operating capacity may be a factor in trying to understand actual and potential utilization, since the amount of stacked horsepower can vary as a result of operating decisions without regard to the underlying activity, we do not consider stacked horsepower by itself to be a material metric for investors. In light of the Staff’s comment, we recognize that this information could be helpful when considered with the

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other performance information we provide investors. As such, on page 23 of our Form 10-Q for the fiscal quarter ended September 30, 2015, we have disclosed the approximate amount of our stacked fracturing horsepower.

7. Please tell us more about the process through which you evaluate your fleet of marketable pressure pumping equipment for impairment pursuant to FASB ASC 360-10-35. With your response, also tell us about your impairment analysis as of June 30, 2015. In this connection, we note that your response to prior comment 4 states that you will not experience any meaningful increase in demand for pressure pumping equipment until oil or natural gas prices improve. We also note the disclosure in your Form 10-Q stating that your pressure pumping business is continuing to experience the effects of reduced spending by customers and downward pressure on pricing and that you expect to experience further declines in pressure pumping activity and pricing.

As noted in our responses to comments 2 and 5 above, during the first quarter of 2015, oil prices averaged $48.54 per barrel and reached a low of $43.39 per barrel on March 17, 2015. Oil prices improved during the second quarter of 2015 and averaged $57.85 per barrel. Although a price improvement occurred earlier than we projected, this improvement was generally consistent with our assumption at December 31, 2014, that oil prices would improve late in 2015 and continue to improve in 2016, which would result in improved activity levels for the pressure pumping business. During the second quarter of 2015 as oil prices increased, we received requests from customers to reactivate drilling rigs to resume operations in the third quarter of 2015. We believed this was an indication that future activity levels would be improving for both the contract drilling and pressure pumping businesses, which was consistent with our expectations at December 31, 2014 and through the first two quarters of 2015. ASC 360-10-35 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. Market conditions at June 30, 2015 were generally consistent with our assumptions at December 31, 2014, and there was no event or change in circumstances that indicated that the carrying amount of the long-lived assets of the pressure pumping business was not recoverable.

During the third quarter of 2015, however, oil prices declined and averaged $46.42 per barrel and reached a new low for 2015 of $38.22 per barrel on August 24, 2015. In response to lower oil prices in the third quarter of 2015, we lowered our expectations with respect to future activity levels in the pressure pumping business. In light of our revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the market for pressure pumping services during the third quarter of 2015, we deemed it necessary to assess the recoverability of long-lived assets for pressure pumping. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our pressure pumping segment. With respect to these assets, future cash flows were estimated over the expected remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated. The expected cash flows for the pressure pumping segment were based on our historical experience of utilization and rates in prior downturns. Also, the expected cash flows for the pressure pumping segment were based on the assumption that activity levels would begin to recover in the first quarter of 2017 in response to improved oil prices. While we believe these assumptions with respect to future pricing for oil and natural gas were reasonable, actual future prices may vary significantly from the ones that we assumed. The timeframe over which oil and natural gas prices will recover is highly uncertain.

The Company acknowledges that:

• the Company 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.

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Very truly yours,

/s/ John E. Vollmer III

John E. Vollmer III

Senior Vice President-Corporate Development,

Chief Financial Officer and Treasurer

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Exhibit 1 – Control Premiums Considered as of December 31, 2014

Acquirer		Acquiree		Date		Premium*
Halliburton		Baker Hughes		December 2014			50	%
Siemens		Dresser Rand		September 2014			32	%
GE		Lufkin Industries		July 2013			38	%
Paragon		Prospector Offshore Drilling		November 2014			49	%

Note: With the exception of the GE transaction, which closed on the date indicated, the above dates represent announcement dates as the transactions had not closed as of December 31, 2014.

* Control premiums are implied based on pre-announcement share values of the acquiree and the announced offer consideration. Where consideration involved cash and securities, values for securities exchanged were also determined pre-announcement.

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