SEC Response Letter

By letter dated December 8, 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 November 4, 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 September 30, 2015. The following numbered paragraphs repeat the comments for your convenience, followed by our responses to those comments.

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

1. The disclosure provided in your Form 10-Q for the period ended September 30, 2015 in response to prior comment 1 includes a statement that, if the current lower commodity price environment lasts into 2017 and beyond, your actual cash flows would likely be less than expected cash flows and could result in impairment charges in the future. As part of your disclosure regarding the analysis you performed to assess the recoverability of long- lived assets, please disclose the percentage by which expected cash flows, on an undiscounted basis, exceeded the carrying value of the long-lived assets within your contract drilling and pressure pumping segments as of September 30, 201, please disclose the percentage by which expected cash flows, on an undiscounted basis, exceeded the carrying value of the long-lived assets within your contract drilling and pressure pumping segments as of September 30, 2015. Refer to section V of SEC Release 33-8350.

Expected cash flows, on an undiscounted basis, exceeded the carrying values of the long-lived assets within the contract drilling and pressure pumping segments by approximately 120% and 60%, respectively.

2. Your response to prior comment 2 states that you recognized an impairment charge during the period ended September 30, 2015 primarily related to rigs that were retired and rigs that remain marketable but were not operating. However, your response does not appear to address stacked non-APEX electric rigs for which an impairment charge was not deemed necessary. Tell us more about your assessment of the recoverability of stacked rigs and explain how factors such as decreased demand for your drilling rigs and the industry shift to higher specification drilling rigs affected your impairment analysis. Refer to FASB ASC 360-10-35.

As disclosed on page 12 of our Form 10-Q for the quarter ended September 30, 2015, we periodically evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. We recorded a $131 million charge to write-off excess and obsolete equipment as a result of this evaluation, which was performed prior to our ASC 360-10-35 assessment of recoverability. For the years ended December 31, 2014, 2013 and 2012, respectively, we recorded charges of $77.9 million, $37.8 million and $5.2 million for excess and obsolete equipment in our contract drilling business.

Management expected that the non-APEX^® electric rigs that were not working but remain in the marketed fleet as of September 30, 2015 will go back to work when commodity prices improve. The nine non-APEX^® electric rigs that management did not expect to work when commodity prices improve were retired during the third quarter of 2015. We consider the 41 non-APEX^® rigs that remain in our marketed drilling rig fleet to be high specification drilling rigs.

As disclosed on page 12 of our Form 10-Q for the quarter ended September 30, 2015, our Step 1 analysis as required by ASC 360-10-35 indicated that, on an undiscounted basis, expected cash flows of our drilling fleet exceeded the carrying value of these long-lived assets, and no impairment was indicated.

3. Your response to prior comment 3 states that, to determine the control premium used in calculating your enterprise value, you reviewed the implied premiums in acquisitions that you believed to be relevant and were in the oilfield service industry. Please provide us with additional detail explaining how you analyzed the premiums from the transactions identified in your response. As part of your response, address the qualitative factors used to identify market participant synergies and tell us about the calculations you performed to support the control premium used to determine your enterprise value.

Based on our experience, knowledge of mergers and acquisitions and on a consultation with an investment banker that specializes in the oilfield services industry, we believe that a control premium of 20% represents the low end of the range of potential control premiums that might be realized in any purchase of the Company in which the buyer would obtain control. Considering that this was a qualitative analysis and that the indicated control premium was at the low end of the range of potential control premiums, we did not believe that it was necessary to identify specific synergies in the identified transactions and no additional calculations were performed.

As noted in our response to your comment 3 in our letter dated August 31, 2015, the control premium was one of a number of factors considered in forming our overall conclusion that it was more likely than not that the fair values of our reporting units were greater than their carrying amounts. Those additional factors included, but were not limited to, our expectation at that time that oil prices would improve by the end of 2015, the increase in the Company’s stock price before the Form 10-K was filed and

the third party reports in December 2014 that estimated that the net asset value of the Company’s drilling and pressure pumping assets was greater than total stockholders’ equity at December 31, 2014. In forming our overall conclusion, we placed greater weight on the expectation that oil prices would improve by the end of 2015 than on our December 31, 2014 stock price and the indicated control premium, especially given that the difference between our book equity and our market capitalization had recovered from a shortfall of approximately 20% to only 10% between year-end and the filing of our annual report.

4. Your response to prior comment 4 states that 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. Please tell us about the discrete financial information available for each rig and describe the process through which the operating results for each rig are reviewed. Refer to FASB ASC 350- 20-35-34.

Most of our drilling contracts are entered into with established customers on a competitive bid or negotiated basis. The customer provides us with their rig specification requirements, and based on their requirements we provide a bid. Subject to availability, we have many rigs that can drill any given well. Additionally, after a rig is assigned to a contract it may be replaced by another rig for a variety of reasons.

We account for the revenue and direct well cost from each contract using a project accounting system, which allows us to evaluate contract performance including metrics such as revenue per drilling day and direct well costs per day. Direct well costs are expenses incurred pursuant to provisions of customer contracts that do not relate to rig personnel or the cost of operating the rig. We consider costs associated with operating a rig (including rig personnel) direct rig costs and account for them by rig.

Revenues and direct well costs associated with the contracts and direct rig costs associated with operating the rigs are summarized into a single income statement that includes all contracts and rigs. Our drilling segment President concentrates his review of our drilling segment’s operating results on this combined income statement. To the extent the drilling segment President has questions about balances reflected in the combined income statement, drill down capability and alternate views of the information are available in our financial reporting systems whereby the combined information discussed above may be reviewed on a contract-by-contract or rig-by-rig basis. The rig-by-rig comparisons are typically focused on direct rig costs since they are similar across all rigs.

Other members of the drilling segment management team follow the same approach as the drilling segment President, except the combined income statement they receive is limited to the contracts and rigs that are under their management.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 23

5. Your response to prior comment 7 states that the expected cash flows used to test your pressure pumping segment for impairment as of September 30, 2015 were based on your historical experience of utilization and rates in prior downturns. Tell us about the prior downturns considered in your impairment assessment and explain how they compare to current market conditions. Also, explain your basis for the assumption that a recovery in activity levels will occur in the first quarter of 2017 in response to improved oil prices.

In the pressure pumping market, most work is performed on a spot-basis and not pursuant to a term contract. For the small percentage of work that is performed pursuant to term contracts, those term contracts typically do not guarantee full utilization. Pressure pumping activity is correlated to commodity prices. Demand for pressure pumping services declines when commodity prices are low, resulting in excess capacity in terms of both equipment and personnel. In response, pressure pumping service providers typically lower the prices they charge for their services in an effort to maintain some utilization of their equipment and people. During periods with low commodity prices, pressure pumping service providers often operate at very low or negative cash margins. Based upon publicly available information, we believe

that many pressure pumping service providers are currently operating near or below cash breakeven margins. When commodity prices improve, we expect there will be more demand for pressure pumping services and, as a result, prices for pressure pumping services would be expected to increase. This expectation is consistent with our experience in 2008 and 2009 when oil prices decreased and there was an industry downturn and in 2010 through 2014 when oil prices increased and the industry recovered. We believe the downturn in 2008 and 2009 is the only comparable downturn for the pressure pumping segment because in recent years the pressure pumping business has fundamentally changed as a result of the increased drilling and completion of horizontal wells in connection with the development of shale and unconventional plays. This change in the pressure pumping business has resulted in a large increase in the number of stages per well, greater complexity of jobs and an increase in the overall size of the average job.

With respect to our oil price assumption, we monitored reports by industry analysts and believed the consensus among these analysts was for oil prices to recover in the second half of 2016. Utilizing this assumption, we expected pressure pumping activity would begin to recover in the first quarter of 2017.

6. We note the disclosure on page 14 your filing which states that, in light of your revised expectations of the duration of the lower commodity price environment and the related deterioration of the markets for contract drilling and pressure pumping services, you performed a goodwill impairment test as of September 30, 2015. Based on the results of the first step of the goodwill impairment test as of September 30, 2015, you concluded that no impairment was indicated in your contract drilling reporting unit. Please revise to state the percentage by which the fair value of this reporting exceeded the carrying value as of September 30, 2015.

Based on the results of the first step of the goodwill impairment test as of September 30, 2015, the fair value of the contract drilling reporting unit exceeded its carrying value by approximately 15% and management concluded that no impairment was indicated in its contract drilling reporting unit; however, impairment was indicated in its pressure pumping reporting unit.

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


Re:		Patterson-UTI Energy, Inc.
		Form 10-K for Fiscal Year Ended December 31, 2014
		Form 10-Q for Fiscal Quarter Ended September 30, 2015
		Response Dated November 4, 2015
		File No. 000-22664